WO2008033591A1 - Produits alourdissants revêtus d'un dispersant - Google Patents

Produits alourdissants revêtus d'un dispersant Download PDF

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Publication number
WO2008033591A1
WO2008033591A1 PCT/US2007/071338 US2007071338W WO2008033591A1 WO 2008033591 A1 WO2008033591 A1 WO 2008033591A1 US 2007071338 W US2007071338 W US 2007071338W WO 2008033591 A1 WO2008033591 A1 WO 2008033591A1
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WO
WIPO (PCT)
Prior art keywords
fluid
weighting agent
dispersant
coated
sized
Prior art date
Application number
PCT/US2007/071338
Other languages
English (en)
Inventor
Jarrod Massam
Original Assignee
M-I Llc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US11/741,199 external-priority patent/US20080064613A1/en
Priority to MX2009002464A priority Critical patent/MX2009002464A/es
Priority to EA200701191A priority patent/EA012144B1/ru
Priority to CN200780033635.XA priority patent/CN101511968B/zh
Priority to AU2007294625A priority patent/AU2007294625B2/en
Priority to EP07784448A priority patent/EP1987112A4/fr
Application filed by M-I Llc filed Critical M-I Llc
Priority to NZ575007A priority patent/NZ575007A/en
Priority to GB0812577A priority patent/GB2447393B/en
Priority to BRPI0716793-8A priority patent/BRPI0716793A2/pt
Priority to CA2661918A priority patent/CA2661918C/fr
Publication of WO2008033591A1 publication Critical patent/WO2008033591A1/fr
Priority to NO20083088A priority patent/NO20083088L/no

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Classifications

    • A—HUMAN NECESSITIES
    • A61—MEDICAL OR VETERINARY SCIENCE; HYGIENE
    • A61N—ELECTROTHERAPY; MAGNETOTHERAPY; RADIATION THERAPY; ULTRASOUND THERAPY
    • A61N1/00—Electrotherapy; Circuits therefor

Definitions

  • the invention relates generally to fluids and surface coated solid materials for use in a wellbore fluid.
  • drill bit cutting surfaces When drilling or completing wells in earth formations, various fluids typically are used in the well for a variety of reasons.
  • Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling- in (i.e., drilling in a targeted petroliferous formation), transportation of "cuttings" (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
  • drilling fluids should be pumpable under pressure down through strings of drilling pipe, then through and around the drilling bit head deep in the earth, and then returned back to the earth surface through an annulus between the outside of the drill stem and the hole wall or casing.
  • drilling fluids should suspend and transport solid particles to the surface for screening out and disposal.
  • the fluids should be capable of suspending additive weighting agents (to increase specific gravity of the mud), generally finely ground barites (barium sulfate ore), and transport clay and other substances capable of adhering to and coating the borehole surface.
  • Drilling fluids are generally characterized as thixotropic fluid systems. That is, they exhibit low viscosity when sheared, such as when in circulation (as occurs during pumping or contact with the moving drilling bit). However, when the shearing action is halted, the fluid should be capable of suspending the solids it contains to prevent gravity separation. In addition, when the drilling fluid is under shear conditions and a free-flowing near-liquid, it must retain a sufficiently high enough viscosity to carry all unwanted particulate matter from the bottom of the well bore to the surface. The drilling fluid formulation should also allow the cuttings and other unwanted particulate material to be removed or otherwise settle out from the liquid fraction.
  • Drilling fluids having the rheological profiles that enable these wells to be drilled more easily.
  • Drilling fluids having tailored rheological properties ensure that cuttings are removed from the wellbore as efficiently and effectively as possible to avoid the formation of cuttings beds in the well which can cause the drill string to become stuck, among other issues.
  • an enhanced profile is necessary to prevent settlement or sag of the weighting agent in the fluid, if this occurs it can lead to an uneven density profile within the circulating fluid system which can result in well control (gas/fluid influx) and wellbore stability problems (caving/fractures).
  • the fluid must be easy to pump so it requires the minimum amount of pressure to force it through restrictions in the circulating fluid system, such as bit nozzles or down-hole tools. Or in other words, the fluid must have the lowest possible viscosity under high shear conditions. Conversely, in zones of the well where the area for fluid flow is large and the velocity of the fluid is slow or where there are low shear conditions, the viscosity of the fluid needs to be as high as possible in order to suspend and transport the drilled cuttings. This also applies to the periods when the fluid is left static in the hole, where both cuttings and weighting materials need to be kept suspended to prevent settlement.
  • the viscosity of the fluid should not continue to increase under static conditions to unacceptable levels. Otherwise when the fluid needs to be circulated again this can lead to excessive pressures that can fracture the formation or alternatively it can lead to lost time if the force required to regain a fully circulating fluid system is beyond the limits of the pumps.
  • Wellbore fluids must also contribute to the stability of the well bore, and control the flow of gas, oil or water from the pores of the formation in order to prevent, for example, the flow or blow out of formation fluids or the collapse of pressured earth formations.
  • the column of fluid in the hole exerts a hydrostatic pressure proportional to the depth of the hole and the density of the fluid.
  • High- pressure formations may require a fluid with a specific gravity as high as 3.0.
  • a variety of materials are presently used to increase the density of wellbore fluids. These include dissolved salts such as sodium chloride, calcium chloride and calcium bromide. Alternatively, powdered minerals such as barite, calcite and hematite are added to a fluid to form a suspension of increased density.
  • finely divided metal such as iron
  • the weight material includes iron/steel ball-shaped particles having a diameter less than 250 ⁇ m and preferentially between 15 and 75 ⁇ m has also been described.
  • the use of finely powdered calcium or iron carbonate has also been proposed; however, the plastic viscosity of such fluids rapidly increases as the particle size decreases, limiting the utility of these materials.
  • weighting agents such as powdered barite exhibit an average particle diameter (d 5 o) in the range of 10-30 ⁇ m.
  • a gellant such as bentonite for water-based fluids, or organically modified bentonite for oil-based fluids.
  • a soluble polymer viscosifier such as xanthan gum may be also added to slow the rate of the sedimentation of the weighting agent.
  • the fluid viscosity plastic viscosity and/or yield point
  • a viscosifier is used to maintain a desirable level of solids suspension.
  • the sedimentation (or "sag") of particulate weighting agents becomes more critical in wellbores drilled at high angles from the vertical, in that a sag of, for example, one inch (2.54 cm) can result in a continuous column of reduced density fluid along the upper portion of the wellbore wall.
  • a sag of, for example, one inch (2.54 cm) can result in a continuous column of reduced density fluid along the upper portion of the wellbore wall.
  • Such high angle wells are frequently drilled over large distances in order to access, for example, remote portions of an oil reservoir. In such instances it is important to minimize a drilling fluid's plastic viscosity in order to reduce the pressure losses over the borehole length.
  • a high density also should be maintained to prevent a blow out.
  • the issues of sag become increasingly important to avoid differential sticking or the settling out of the particulate weighting agents on the low side of the wellbore.
  • embodiments disclosed herein relate to a method of formulating a wellbore fluid that includes providing a base fluid; and adding a sized weighting agent coated with a dispersant made by the method of dry blending a weighting agent and a dispersant to form a sized weighting agent coated with the dispersant.
  • embodiments disclosed herein relate to a wellbore fluid that includes a base fluid; and a sized weighting agent coated with a dispersant made by the method of dry blending a weighting agent and a dispersant to form a sized weighting agent coated with the dispersant.
  • FIG. 1 shows a flow diagram of a dry blending process in accordance with one embodiment disclosed herein.
  • embodiments disclosed herein relate to dispersant coatings on weighting agents used in wellbore fluids. In another aspect, embodiments disclosed herein relate to the formulation of wellbore fluids that include dispersant coated weighting agents.
  • a weighting agent may be coated with a dispersant by a dry blending process.
  • the resultant coated weighting agent may be added in new drilling fluid formulations or added to existing formulations.
  • dry blending refers to a process in which the weighting agent is mixed and coated with a dispersant in the absence of a solvent.
  • An analogous process in the presence of solvent generating colloidal coated particles has been disclosed in U.S. Patent Application No. 20040127366 assigned to the assignee of the present application, which is herein incorporated by reference.
  • the term “sized weighting agent” refers to weighting agents having particle size distribution reduced below conventional API specified distribution.
  • the weighting agent may be dry blended with the dispersant in a comminution process (grinding) process or by other means such as, for example, thermal desorption.
  • Weighting agents used in embodiments disclosed herein may include a variety of compounds well known to one of skill in the art.
  • the weighting agent may be selected from materials including, for example, barium sulphate (barite), calcium carbonate, dolomite, ilmenite, hematite, olivine, siderite, manganese oxide, and strontium sulphate.
  • barium sulphate barite
  • calcium carbonate dolomite, ilmenite, hematite, olivine, siderite, manganese oxide, and strontium sulphate.
  • the weighting agent may be a sized weighting agent having a dgo ranging from 1 to 25 ⁇ m and a d 5 o ranging from 0.5 to 10 ⁇ m.
  • the sized weighting agent includes particles having a dgo ranging from 2 to 8 ⁇ m and a ds 0 ranging from 0.5 to 4 ⁇ m.
  • the weighting agent may have a particle size distribution other than a monomodal distribution. That is, the weighting agent may have a particle size distribution that, in various embodiments, may be monomodal, which may or may not be Gaussian, bimodal, or polymodal.
  • Particles having these size distributions may be obtained by several means.
  • sized particles such as a suitable barite product having similar particle size distributions as disclosed herein, may be commercially. purchased.
  • a coarser ground suitable material may be obtained, and the material may be further ground by any known technique to the desired particle size.
  • Such techniques include jet-milling, high performance dry milling techniques, or any other technique that is known in the art generally for milling powdered products.
  • appropriately sized particles of barite may be selectively removed from a product stream of a conventional barite grinding plant, which may include selectively removing the fines from a conventional API barite grinding operation.
  • Fines are often considered a by-product of the grinding process, and conventionally these materials are blended with courser materials to achieve API grade barite. However, in accordance with the present disclosure, these by-product fines may be further processed via an air classifier to achieve the particle size distributions disclosed herein.
  • the sized weighting agents may be formed by chemical precipitation. Such precipitated products may be used alone or in combination with mechanically milled products.
  • the dispersant may be selected from carboxylic acids of molecular weight of at least 150 Daltons such as oleic acid and polybasic fatty acids, alkylbenzene sulphonic acids, alkane sulphonic acids, linear alpha-olefin sulphonic acid, phospholipids such as lecithin, including salts thereof and including mixtures therof.
  • carboxylic acids of molecular weight of at least 150 Daltons such as oleic acid and polybasic fatty acids, alkylbenzene sulphonic acids, alkane sulphonic acids, linear alpha-olefin sulphonic acid, phospholipids such as lecithin, including salts thereof and including mixtures therof.
  • Synthetic polymers may also be utilized such as HYPERMER OM-I (Imperial Chemical Industries, PLC, London, United Kingdom) or polyacrylate esters, for example.
  • Such polyacrylate esters may incude polymers of stearyl methacryl
  • the corresponding acids methacrylic acid and/or acrylic acid may be used.
  • acrylate or other unsaturated carboxylic acid monomers or esters thereof may be used to achieve substantially the same results as disclosed herein.
  • a water soluble polymer of molecular weight of at least 2000 Daltons may be used in a particular embodiment.
  • water soluble polymers may include a liomopolymer or copolymer of any monomer selected from acrylic acid, itaconic acid, maleic acid or anhydride, hydroxypropyl acrylate vinylsulphonic acid, acrylamido 2-propane sulphonic acid, acrylamide, styrene sulphonic acid, acrylic phosphate esters, methyl vinyl ether and vinyl acetate or salts thereof.
  • the polymeric dispersant may have an average molecular weight from about
  • the polymeric dispersant be polymerized prior to or simultaneously with the dry blending processes disclosed herein.
  • Such polymerizations may involve, for example, thermal polymerization, catalyzed polymerization or combinations thereof.
  • Coating of the weighting agent with the dispersant may be performed in a dry blending process such that the process is substantially free of solvent.
  • a dry blending process such that the process is substantially free of solvent.
  • the process includes blending the weighting agent 10 and a dispersant 12 at a desired ratio to form a blended material.
  • the weighting agent 10 may be unsized initially and rely on the blending process to grind the particles into the desired size range as disclosed above.
  • the process may begin with sized weighting agents.
  • the blended material 14 may then be fed to a heat exchange system 16, such as a thermal desorption system.
  • the mixture may be forwarded through the heat exchanger using a mixer 18, such as a screw conveyor.
  • the polymer may remain associated with the weighting agent.
  • the polymer/weighting agent mixture 20 may then be separated into polymer coated weighting agent 22, unassociated polymer 24, and any agglomerates 26 that may have formed.
  • the unassociated polymer 24 may optionally be recycled to the beginning .of the process, if desired.
  • the dry blending process alone may serve to coat the weighting agent without heating.
  • a sized weighting agent may be coated by thermal adsorption as described above, in the absence of a dry blending process.
  • a process for making a coated substrate may include heating a sized weighting agent to a temperature sufficient to react a monomelic dispersant as described above onto the weighting agent to form a polymer coated sized weighting agent and recovering the polymer coated weighting agent.
  • one may use a catalyzed process to form the polymer in the presence of the sized weighting agent.
  • the polymer may be preformed and may be thermally adsorbed onto the sized weighting agent.
  • the dispersant is coated onto the weighting agent during the grinding process. That is to say, coarse weighting agent is ground in the presence of a relatively high concentration of dispersant such that the newly formed surfaces of the fine particles are exposed to and thus coated by the dispersant. It is speculated that this allows the dispersant to find an acceptable conformation on the particle surface thus coating the surface. Alternatively it is speculated that because a relatively higher concentration of dispersant in the grinding fluid, as opposed to that in a drilling fluid, the dispersant is more likely to be adsorbed (either physically or chemically) to the particle surface.
  • coating of the surface is intended to mean that a sufficient number of dispersant molecules are absorbed (physically or chemically) or otherwise closely associated with the surface of the particles so that the fine particles of material do not cause the rapid rise in viscosity observed in the prior art.
  • dispersant molecules may not actually be fully covering the particle surface and that quantification of the number of molecules is very difficult.
  • dry coated particles may be obtained from an oil-based slurry through methods such as spray drying and thermal desorption, for example.
  • the dispersant may comprise from about 1% to about 10% of the total mass of the dispersant plus weighting agent.
  • the dry coated weighting agent may be used in a wellbore fluid formulation.
  • the wellbore fluid may be a water-based fluid, an invert emulsion or an oil-based fluid.
  • Water-based wellbore fluids may have an aqueous fluid as the base solvent and a dispersant coated weighting agent.
  • the aqueous fluid may include at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds and mixtures thereof.
  • the aqueous fluid may be formulated with mixtures of desired salts in fresh water.
  • Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example.
  • the brine may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water.
  • Salts that may be found in seawater include, but are not limited to, sodium, calcium, sulfur, aluminum, magnesium, potassium, strontium, silicon, lithium, and phosphorus salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, and fluorides. Salts that may be incorporated in a given brine include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts. Additionally, brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution, hi one embodiment, the density of the drilling fluid may be controlled by increasing the salt concentration in the brine (up to saturation). In a particular embodiment, a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium.
  • the oil-based/invert emulsion wellbore fluids may include an oleaginous continuous phase, a non- oleaginous discontinuous phase, and a dispersant coated weighting agent.
  • a dispersant coated weighting agent may be modified in accordance with the desired application. For example, modifications may include the hydrophilic/hydrophobic nature of the dispersant.
  • the oleaginous fluid may be a liquid and more preferably is a natural or synthetic oil and more preferably the oleaginous fluid is selected from the group including diesel oil; mineral oil; a synthetic oil, such as hydrogenated and unhydrogenated olefins including poly(alpha-olefins), linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alkyl ethers of fatty acids, mixtures thereof and similar compounds known to one of skill in the art; and mixtures thereof.
  • diesel oil such as hydrogenated and unhydrogenated olefins including poly(alpha-olefins), linear and branch olefins and the like, polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids, specifically straight chain, branched and cyclical alky
  • the concentration of the oleaginous fluid should be sufficient so that an invert emulsion forms and may be less than about 99% by volume of the invert emulsion.
  • the amount of oleaginous fluid is from about 30% to about 95% by volume and more preferably about 40% to about 90% by volume of the invert emulsion fluid.
  • the oleaginous fluid in one embodiment, may include at least 5% by volume of a material selected from the group including esters, ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations thereof.
  • the non-oleaginous fluid used in the formulation of the invert emulsion fluid disclosed herein is a liquid and may be an aqueous liquid.
  • the non-oleaginous liquid may be selected from the group including sea water, a brine containing organic and/or inorganic dissolved salts, liquids containing water-miscible organic compounds and combinations thereof.
  • the amount of the non-oleaginous fluid is typically less than the theoretical limit needed for forming an invert emulsion.
  • the amount of non-oleaginous fluid is less that about 70% by volume and preferably from about 1 % to about 70% by volume.
  • the non-oleaginous fluid is preferably from about 5% to about 60% by volume of the invert emulsion fluid.
  • the fluid phase may include either an aqueous fluid or an oleaginous fluid, or mixtures thereof.
  • coated barite or other weighting agents may be included in a wellbore fluid comprising an aqueous fluid that includes at least one of fresh water, sea water, brine, and combinations thereof.
  • the fluids disclosed herein are especially useful in the drilling, completion and working over of subterranean oil and gas wells.
  • the fluids disclosed herein may find use in formulating drilling muds and completion fluids that allow for the easy and quick removal of the filter cake.
  • Such muds and fluids are especially useful in the drilling of horizontal wells into hydrocarbon bearing formations.
  • Conventional methods can be used to prepare the drilling fluids disclosed herein in a manner analogous to those normally used, to prepare conventional water- and oil-based drilling fluids.
  • a desired quantity of water-based fluid and a suitable amount of the dispersant coated weighting agent are mixed together and the remaining components of the drilling fluid added sequentially with continuous mixing.
  • a desired quantity of oleaginous fluid such as a base oil, a non-oleaginous fluid and a suitable amount of the dispersant coated weighting agent are mixed together and the remaining components are added sequentially with continuous mixing.
  • An invert emulsion may be formed by vigorously agitating, mixing or shearing the oleaginous fluid and the non-oleaginous fluid.
  • additives that may be included in the wellbore fluids disclosed herein include for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents and cleaning agents.
  • wetting agents for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents and cleaning agents.
  • wetting agents for example, wetting agents, organophilic clays, viscosifiers, fluid loss control agents, surfactants, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners, thinning agents and cleaning agents.
  • an existing drilling fluid formulation may be modified with a dispersant coated weighting agent.
  • a dispersant coated weighting agent for example, one may add dispersant-coated weighting agents of the present disclosure to the wellbore fluids disclosed in U.S. Patent Application 20040127366 (the '366 application) assigned to the assignee of the present application.
  • the wellbore fluids of the '366 application contain colloidal coated weighting agent particles derived from a blending process in the presence of solvent.
  • colloidal refers to a suspension of the particles, and does not impart any specific size limitation. Rather, the size of the micronized weighting agents of the present disclosure may vary in range and are only limited by the claims of the present application.
  • the dispersant coated weighting agent of the present disclosure may be added to any type of existing wellbore fluid formulation.
  • the following examples include exemplary coated and uncoated weighting agents and experimental data showing their fluid loss and rheological properties.
  • Oil- based drilling fluids were tested over a mud weight range of 12.5-22.0 ppg and temperatures of 250-350 °F using a polyacrylate polymer coated barite as the weighting material.
  • a 14 pounds per gallon (ppg) fluid was formulated with EDC 99DW, a highly hydrogenated mineral oil (M-I LLC, Houston, TX), as the oleaginous phase.
  • 14 ppg solutions were formulated with dispersant coated barite as well as uncoated barite. Quantities of each component are expressed in pounds per barrel (ppb) as shown in Table 1 below (EMUL HTTM and TRUVISTM are each available from M-I LLC, Houston, TX).
  • results show an enhanced rheological profile with the coated barite giving a lower yield point (YP) 3 low-shear rate viscosities and gel strength.
  • the fluid loss also shows improvement when using the coated barite.
  • an existing fluid formulation may be weighted up with dispersant-coated weighting agents.
  • dispersant-coated weighting agents The following experiments were earned out with a 16 ppg oil-based aged at 350 °F. Quantities of each component are expressed in pounds per barrel (ppb) as shown in Table 3 below (EMUL HTTM, VERSAGEL ® , and VERSATROL ® are each available from M-I LLC 3 Houston, TX).
  • a 20 ppg fluid was formulated to an OWR of 90/10 and aged at 350 0 F.
  • a 14 pounds per gallon (ppg) fluid was formulated with DFl as the oleaginous phase.
  • Three 14 ppg were formulated with micronized manganese oxide: a mud containing uncoated micronized manganese oxide, drilling mud including uncoated micronized manganese oxide and a dispersant (EMI759, available from M-I LLC, Houston, TX), and a dispersant (EMI759) coated manganese oxide.
  • results show an enhanced rheological profile with the coated manganese oxide giving a lower yield point (YP), low-shear rate viscosities and gel strength.
  • the fluid loss also shows improvement when using the dispersant coated manganese oxide.
  • results in Table 9 also show the benefit of coating the weighting agent with a dispersant as opposed to only including the dispersant in the mud formulation.
  • the benefits of the coated weight material may be optimum when a sized weighting agent is used.
  • a sized range may allow both ease of material dispersion and a requirement of fewer drilling fluid additives, such as an emulsifier and organoclay, to achieve the desired fluid properties.
  • drilling fluid additives such as an emulsifier and organoclay
  • fluids such as those disclosed herein may allow optimization in each of those aspects.
  • the coated weighting agent is formed in a dry process, it may be used without requiring additional weighting-up.

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Abstract

L'invention concerne un procédé de préparation de fluide de puits de forage qui consiste à prendre un fluide de base, à ajouter un produit alourdissant calibré revêtu d'un dispersant fabriqué par le procédé de mélange à sec de produit alourdissant et de dispersant afin de former un produit alourdissant calibré revêtu de dispersant.
PCT/US2007/071338 2006-09-11 2007-06-15 Produits alourdissants revêtus d'un dispersant WO2008033591A1 (fr)

Priority Applications (10)

Application Number Priority Date Filing Date Title
CA2661918A CA2661918C (fr) 2006-09-11 2007-06-15 Produits alourdissants revetus d'un dispersant
EA200701191A EA012144B1 (ru) 2006-09-11 2007-06-15 Утяжелители с покрытием из диспергатора
CN200780033635.XA CN101511968B (zh) 2006-09-11 2007-06-15 分散剂包覆的增重剂
AU2007294625A AU2007294625B2 (en) 2006-09-11 2007-06-15 Dispersant coated weighting agents
EP07784448A EP1987112A4 (fr) 2006-09-11 2007-06-15 Produits alourdissants revêtus d'un dispersant
MX2009002464A MX2009002464A (es) 2006-09-11 2007-06-15 Agentes densificantes recubiertos de dispersante.
NZ575007A NZ575007A (en) 2006-09-11 2007-06-15 Dispersant coated weighting agents
GB0812577A GB2447393B (en) 2006-09-11 2007-06-15 Dispersant coated weighting agents
BRPI0716793-8A BRPI0716793A2 (pt) 2006-09-11 2007-06-15 agentes de peso revestidos com dispersante
NO20083088A NO20083088L (no) 2006-09-11 2008-07-09 Dispergeringsmiddelbelagte vektmidler

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US82515606P 2006-09-11 2006-09-11
US60/825,156 2006-09-11
US11/741,199 2007-04-27
US11/741,199 US20080064613A1 (en) 2006-09-11 2007-04-27 Dispersant coated weighting agents

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WO2008033591A1 true WO2008033591A1 (fr) 2008-03-20

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Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013126219A1 (fr) * 2012-02-23 2013-08-29 Halliburton Energy Services, Inc. Agents alourdissants particulaires modifiés et leurs procédés d'utilisation
US11285489B2 (en) 2016-09-29 2022-03-29 Halliburton Energy Services, Inc. Milling oilfield particulates

Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3887474A (en) * 1971-08-10 1975-06-03 Metallgesellschaft Ag Process for producing a filler for drilling mud
US4476029A (en) * 1982-05-26 1984-10-09 W. R. Grace & Co. High temperature dispersant
US4770795A (en) * 1987-08-24 1988-09-13 Nalco Chemical Company Calcium tolerant deflocculant for drilling fluids

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3887474A (en) * 1971-08-10 1975-06-03 Metallgesellschaft Ag Process for producing a filler for drilling mud
US4476029A (en) * 1982-05-26 1984-10-09 W. R. Grace & Co. High temperature dispersant
US4770795A (en) * 1987-08-24 1988-09-13 Nalco Chemical Company Calcium tolerant deflocculant for drilling fluids

Non-Patent Citations (2)

* Cited by examiner, † Cited by third party
Title
H. C. H. DARLEY; GEORGE R. GRAY: "Composition and Properties of Drilling and Completion Fluids", 1988, pages: 116
See also references of EP1987112A4 *

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013126219A1 (fr) * 2012-02-23 2013-08-29 Halliburton Energy Services, Inc. Agents alourdissants particulaires modifiés et leurs procédés d'utilisation
AU2013222778B2 (en) * 2012-02-23 2015-05-07 Halliburton Energy Services, Inc. Modified particulate weighting agents and methods of using the same
US11285489B2 (en) 2016-09-29 2022-03-29 Halliburton Energy Services, Inc. Milling oilfield particulates

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