WO2010121027A2 - Lubrifiant pour boues à base d'eau et procédés d'utilisation associés - Google Patents

Lubrifiant pour boues à base d'eau et procédés d'utilisation associés Download PDF

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Publication number
WO2010121027A2
WO2010121027A2 PCT/US2010/031241 US2010031241W WO2010121027A2 WO 2010121027 A2 WO2010121027 A2 WO 2010121027A2 US 2010031241 W US2010031241 W US 2010031241W WO 2010121027 A2 WO2010121027 A2 WO 2010121027A2
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WO
WIPO (PCT)
Prior art keywords
fluid
agent
wellbore fluid
water
wellbore
Prior art date
Application number
PCT/US2010/031241
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English (en)
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WO2010121027A3 (fr
Inventor
Eugene Dakin
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M-I L.L.C.
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Filing date
Publication date
Application filed by M-I L.L.C. filed Critical M-I L.L.C.
Priority to CA2758778A priority Critical patent/CA2758778C/fr
Publication of WO2010121027A2 publication Critical patent/WO2010121027A2/fr
Publication of WO2010121027A3 publication Critical patent/WO2010121027A3/fr

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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
    • C09K8/14—Clay-containing compositions
    • C09K8/18—Clay-containing compositions characterised by the organic compounds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/34—Lubricant additives

Definitions

  • Embodiments disclosed herein relate to components of wellbore fluids (muds).
  • embodiments relate to water-based muds and components thereof.
  • various fluids are typically used in the well for a variety of functions.
  • the fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through the wellbore to the surface.
  • the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
  • the drilling fluid takes the form of a "mud," i.e., a liquid having solids suspended therein.
  • the solids function to impart desired rheological properties to the drilling fluid and also to increase the density thereof in order to provide a suitable hydrostatic pressure at the bottom of the well.
  • 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 wellbore 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 wells to be drilled more easily 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.
  • Drilling fluid hydraulics perspective equivalent circulating density
  • 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) problems 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.
  • the fluid must have the lowest possible viscosity under high 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 lead to lost time if the force required to regain a fully circulating fluid system is beyond the limits of the pumps.
  • Drilling fluids are typically classified according to their base material.
  • the drilling mud may be either a water-based mud having solid particles suspended therein or an oil-based mud with water or brine emulsified in the oil to form a discontinuous phase and solid particles suspended in the oil continuous phase.
  • drill cuttings are conveyed up the hole by the drilling fluid.
  • Water-based drilling fluids may be suitable for drilling in certain types of formations; however, for proper drilling in other formations, it is desirable to use an oil-based drilling fluid.
  • the cuttings With an oil-based drilling fluid, the cuttings, besides ordinarily containing moisture, are coated with an adherent film or layer of oily drilling fluid which may penetrate into the interior of each cutting. This is true despite the use of various vibrating screens, mechanical separation devices, and various chemical and washing techniques. Because of pollution to the environment, whether on water or on land, the cuttings cannot be properly discarded until the pollutants have been removed.
  • oil-based muds have been limited to those situations where they are necessary.
  • the selection of an oil-based wellbore fluid involves a careful balance of both the good and bad characteristics of such fluids in a particular application.
  • An especially beneficial property of oil-based muds is their excellent lubrication qualities. These lubrication properties permit the drilling of wells having a significant vertical deviation, as is typical of off-shore or deep water drilling operations or when a horizontal well is desired. In such highly deviated holes, torque and drag on the drill string are a significant problem because the drill pipe lies against the low side of the hole, and the risk of pipe sticking is high when water-based muds are used. In contrast oil-based muds provide a thin, slick filter cake which helps to prevent pipe sticking.
  • Oil-based muds typically have excellent lubricity properties in comparison to water-based muds, which reduces sticking of the drill pipe due to a reduction in frictional drag.
  • the lubricating characteristics (lubricity) of the drilling mud provide the only known means for reducing the friction.
  • the use of oil-based muds is also common in high temperature wells because oil muds generally exhibit desirable rheological properties over a wider range of temperatures than water-based muds.
  • embodiments disclosed herein relate to a water-based wellbore fluid including an aqueous fluid, a mixed metal oxide-clay complex, and an anionic suppressant, where the anionic suppressant includes a Lewis acid and a lubricant and where the lubricant includes a sulfur containing compound and at least one pH agent, where the at least one pH agent is in an amount sufficient to obtain a pH ranging from about 9 to 13.
  • embodiments disclosed herein relate to a method of treating a wellbore, including mixing an aqueous fluid, a mixed metal oxide-clay complex, an anionic suppressant, a lubricant, and at least one pH agent, to form a water-based wellbore fluid, where the anionic suppressant includes a Lewis acid and where the lubricant includes a sulfur containing compound and where the at least one pH agent is in an amount sufficient to obtain a pH ranging from about 9 to 13, and using the water-based wellbore fluid during a drilling operation.
  • Figure 1 shows an interaction between mixed metal oxide and bentonite in accordance with some embodiments of the invention.
  • embodiments disclosed herein relate to lubricants used in water- based wellbore fluid formulations.
  • embodiments described herein relate to the use of lubricants having sulfur compounds therein capable of imparting lubricity upon a wellbore fluid without negatively interacting with other components of the wellbore fluid.
  • Such embodiments may find particular use in water-based fluids containing, inter alia, mixed metal oxide, clay complexes, anionic suppressants, lubricants, and pH adjusting agents.
  • drilling or wellbore fluids may also comprise various other additives such as viscosifiers, gelling agents, bridging agents, and fluid loss control agents, as known in the art.
  • the lubricant may be formed from several components including at least one sulfur compound.
  • Figure 1 shows an interaction between mixed metal oxide and bentonite in accordance with some embodiments of the invention.
  • the rheological properties are derived from interaction between mixed metal oxides and clay particles. Addition of conventional lubricants to the fluid may cause the lubricant to undesirably interact with the mixed metal oxide-clay complex to result in a sudden drop in viscosity and render the fluid unsuitable for its intended purpose.
  • lubricants or fatty acids such as oleic acid
  • a surface-charged clay such as bentonite
  • a mixed metal oxide component also referred to as a "bentonite extender”
  • lubricants described herein may be comprised of sulfur-containing compounds.
  • lubricants may be sulfide/polymer blends, such as:
  • such sulfide/polymer blends may include a polysulfide such as a hydrocarbon chain with an eight membered ring formed therein:
  • sulfur-sulfur bonds in such sulfur-containing compounds may break and thus provide sulfide anions at high temperatures, which are available to react with iron to form iron sulfide. Formation of iron sulfide on iron surfaces may impart the desired lubricity effect.
  • One exemplary lubricant formulation may include (by volume) about 40-80 percent mineral oil and about 20-60 percent of a sulfide/polymer blend.
  • the lubricant may be EP LUBE (available from M-I Drilling Fluids, Pocra Quay, Aberdeen).
  • sulfide ions available in the fluid may further react with available hydrogen to form hydrogen sulfide and anions, for example, hydrogen sulfide ions (HS " ).
  • sulfide and hydrogen sulfide ions act similar to free fatty acids (“FFAs”) (or other anionic contaminants), in that the anions alter the ionic bonds between mixed or metal oxides in water-based fluids and thereby cause undesirable changes to the viscosity/rheological profile of the water-based fluids.
  • FFAs free fatty acids
  • anionic suppressants may be included with the sulfur containing compound, to minimize the effect of the lubricant on the fluid viscosity.
  • an anionic suppressant may preferentially react with available anions in the fluid to prevent or minimize the interaction of the anions with the mixed metal oxides.
  • anionic suppressants may be comprised of Lewis acids. Examples of Lewis acids include, but are not limited to, magnesium carbonate, aluminum carbonate, iron carbonate, zinc carbonate, zinc chloride, diborane, boron trifiuoride, dialuminum hexachloride, aluminum fluoride, silicon tetrafluoride, phosphorus pentachloride, and sulfur tetrafluoride.
  • the anionic suppressants may act as Lewis acids to precipitate anions, for example sulfide ions, out of the wellbore fluid, thus preventing anions from undesirably altering the ionic interactions between mixed metal oxides and clay particles and thereby preserving the rheological properties of the wellbore fluid.
  • the anionic suppressant may include a Lewis acid to which the anion may be attracted, reducing or preventing the negatively charged anion from interacting with the charged surface of the clay (and displacing the mixed metal oxide).
  • the anionic lubricant By increasing the cationic charge, the effect of an anionic lubricant on the charged clay surface may be reduced or minimized, which thus reduces or minimizes the effect on the fluid rheology.
  • anionic suppressants may include any chemical substance which is added and which can react with one or more sulfide components, FFAs or any other anionic contaminants, to form inert compounds. It may be appropriate to add anionic suppressants to the wellbore fluid in excess in relation to the amount of anions present, or expected amount of anions, to ensure minimal effect on fluid rheology. Additives based on zinc, such as zinc carbonate, zinc hydroxide and organic zinc compounds may provide sulfide absorption and give irreversible reactions with the sulfides to form solid zinc sulfide.
  • pH agents described herein may be added to the fluid formulation to adjust the pH by increasing or lowering the pH of the wellbore fluid, as appropriate.
  • pH agents may be added to obtain a pH of the wellbore fluid ranging from about 9 to 13, or at least about 11.5 in other embodiments.
  • pH agents may include, for example, sodium hydroxide
  • pH agents may include alkali agents, including basic agents.
  • the alkalinity of wellbore fluids may be tested using alkaline indicators P f and M f .
  • the ratio of these, P/M f is a measurement of filtrate alkalinity.
  • P f is the phenolphthalein end point of a filtrate sample using N/50 sulfuric acid
  • M f is the methyl orange or brom cresol green-methyl red end point of a filtrate sample using N/50 sulfuric acid.
  • one method of obtaining P f and M f is to pipette 1 ml of filtrate into a titration dish and add more than 2-3 drops of phenolphthalein, while watching for a color change to pink.
  • the P f is zero and the pH is less than 8.3. If a pink color develops, N/50 sulfuric acid is added until the pink color is discharged. The Pf is the amount of N/50 sulfuric acid (in ml) required to discharge the pink color and the sample is titrated to the P f end point.
  • M f 2-3 drops of bromocresol green-methyl red is added to the same sample used to determine P f .
  • N/50 sulfuric acid is added until the sample turns a light blue color initially, and then to an apple green color, indicating the M f end point (and a pH of about 4.0 to 4.5).
  • the M f is the total volume of N/50 sulfuric acid required to reach the M f end point, including the volume required to reach the P f end point.
  • a P f value indicates the presence of carbonate and hydroxide ions.
  • a M f value indicates the presence of bicarbonate ions.
  • the ratio of P f to M f may indicate the alkalinity of the filtrate sample by estimating the carbonate, bicarbonate, and hydroxyl present in the filtrate.
  • Table 1 shows one example of how to estimate the concentrations of these ions using P f and M f values (as described by DiCorp Procedure ⁇ Diversity Technologies Corporation 2002, Canamara United Supply Ltd.): Table 1. Carbonate, Bicarbonate, and Hydroxyl Concentrations
  • the sample's pH may be checked for a titration endpoint of 8.3 for phenolphthalein and 4.3 for methyl orange to determine P f and M f values.
  • Applicants have surprisingly found that by adjusting the pH of the wellbore fluid when adding lubricity components and anionic suppressant components, the rheology of the fluid is improved. Further, it has surprisingly been found that in some embodiments, a P f /M f ratio of about 1 :2 may advantageously impart improved shear properties to the wellbore fluid compositions. In addition, use of pH agents in such a ratio may advantageously reduce air encapsulation and foaming. In some embodiments, in such a ratio, the lubricants and/or anionic suppressants may increase the tendency of the wellbore fluid to foam and a P/M f ratio of about 1 :2 may advantageously control foaming. Further, small additions of sodium hydroxide may improve air encapsulation.
  • the lubricants of the present disclosure may find particular use in a water-based wellbore fluid that includes a mixed metal oxide-clay complex and an aqueous fluid.
  • the aqueous fluid of the wellbore 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, aluminum, magnesium, potassium, strontium, and lithium, salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, phosphates, sulfates, silicates, 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 wellbore fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution.
  • the density of the wellbore fluid may be controlled by increasing the salt concentration in the brine (up to saturation).
  • 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 water-based wellbore fluid may include a mixed metal oxide-clay complex.
  • Such clays may include those having surface charges thereon, including, for example, bentonite, saponite, hectonite, and kaolinite.
  • GELPLEXTM an untreated bentonite, which is available from M-I L. L. C. (Houston, TX).
  • Clay flakes are made up of a number of crystal platelets each being called a unit layer.
  • the unit layers stack together face-to- face and are held in place by weak attractive forces between the ionic surfaces of the unit layer.
  • the distance between corresponding planes in adjacent unit layers is called the d-spacing.
  • Clay swelling is a phenomenon in which water molecules surround a clay crystal structure (based on attraction to the ionic surface) and position themselves to increase the structure's d-spacing, thus resulting in an increase in volume.
  • Two types of swelling may occur.
  • Surface hydration is one type of swelling in which water molecules are adsorbed on crystal surfaces. Hydrogen bonding holds a layer of water molecules to the oxygen atoms exposed on the crystal surfaces.
  • the ionic surfaces of such clays are usually attractive to cations such as sodium or potassium.
  • the unit layer can serve as cation exchange sites for other cations available in the system.
  • metal cations such as in the form of mixed metal oxides are added to a fluid, the metal cations may replace the sodium or potassium cations.
  • these metal ions are polyvalent, the metals may more strongly associate with the clay surface and/or with neighboring clay platelets. Such phenomenon is described in more detail in U.S. Patent Nos. 5,232,627 and 4,664,843, for example.
  • One commercial example of a mixed metal oxide is DRILPLEXTM Mixed Metal Oxide, also available from M-I L. L. C.
  • the interaction between clay and a mixed metal oxide not only increases the viscosity of the fluid by swelling of the clay as well as formation of a unique electrostatic environment through association of the clay and mixed metal oxide, but the particle complex may also act as a bridging agent to help plug pores of a formation and reduce filtration losses.
  • the ionic interaction between clay and a mixed metal oxide may be disturbed by anions.
  • the negatively charged anion components may attract the cationic mixed metal oxides, thereby interrupting the electrostatic environment and bridging ability.
  • the wellbore fluids may also include other conventional additives known in the art of wellbore fluids, including conventional bridging agents, weighting agents, viscosifiers, gelling agents, fluid loss control agents, foaming agents, etc.
  • conventional viscosifiers such as water soluble polymers and polyamide resins, may also be used.
  • the amount of viscosifier used in the composition can vary upon the end use of the composition. However, normally about 0.1% to 10% by weight range is sufficient for most applications.
  • the water-based wellbore fluid may include a weighting agent.
  • Weighting agents or density materials suitable for use the fluids disclosed herein include galena, hematite, magnetite, iron oxides, illmenite, barite, siderite, celestite, dolomite, calcite, and the like.
  • the quantity of such material added, if any, may depend upon the desired density of the final composition.
  • weighting agent is added to result in a wellbore fluid density of up to about 24 pounds per gallon.
  • the weighting agent may be added up to 21 pounds per gallon in one embodiment, and up to 19.5 pounds per gallon in another embodiment.
  • Conventional bridging agents may include bridging materials suitable for use in the present disclosure include graphite, calcium carbonate (preferably, marble), dolomite (MgCO3.CaCO3), celluloses, micas, proppant materials such as sands or ceramic particles and combinations thereof.
  • Foaming agents may include various ester-, alcohol-, or hydrocarbon-based compounds as known in the art.
  • Two commercial examples of defoaming agents include DEFOAMTM-A and DEFOAMTM-X, both of which are available from M-I L.L.C. (Houston, Texas).
  • fluid loss control agents may be added to the wellbore fluids disclosed herein and are generally selected from a group consisting of synthetic organic polymers, biopolymers, polysaccharide derivatives, and mixtures thereof.
  • the fluid loss control agent should be selected to have low toxicity, compatibility with additional wellbore fluid components, and water-solubility.
  • Fluid loss control agents may include, for example, FLO-PLEXTM which is available from M-I L.L.C.
  • additives that may be included in the wellbore fluids disclosed herein include for example, wetting agents, organophilic clays, soda ash, surfactants, shale inhibitors, filtration reducers, dispersants, interfacial tension reducers, pH buffers, mutual solvents, thinners (such as lignins and tannins), thinning agents and cleaning agents.
  • the water-based fluids described herein may be used during a drilling operation. The fluid may be pumped down to the bottom of the well through a drill pipe, where the fluid emerges through ports in the drilling bit, for example. In one embodiment, the fluid may be used in conjunction with any drilling operation, which may include, for example, vertical drilling, extended reach drilling, and directional drilling.
  • water-based wellbore fluids may be prepared with a large variety of formulations. Specific formulations may depend on the state of drilling a well at a particular time, for example, depending on the depth and/or the composition of the formation.
  • the wellbore fluid compositions described above may be adapted to provide improved water-based drilling muds under conditions of high temperature and pressure, such as those encountered in deep wells.
  • the 10 second gel is the strength of the gel ten seconds after application.
  • the 10 minute gel is the strength of the gel ten minutes after application.
  • the treatments include before hot rolling (BHR) and after hot rolling (AHR), with some treatments performed at room temperature (RT).
  • the rheological properties were further measured using plastic viscosity (PV), yield point (YP) and benchtop coefficient of friction (CoF).
  • Advantages of the embodiments disclosed herein may include enhanced rheological properties of the wellbore fluids that incorporate lubricants, anionic suppressants, and pH agents as described herein.
  • the sulfur component of the lubricant may impart beneficial lubricity to the wellbore fluid.
  • the wellbore fluids including lubricants, anionic suppressants, and pH agents as described herein advantageously provide for improved rheological properties of the fluid.
  • fluids described herein having a P f /M f ratio of about 1 :2 advantageously impart improved shear properties.
  • use of pH agents may advantageously reduce air encapsulation and foaming.
  • a P f /M f ratio of about 1 :2 may advantageously control foaming.

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  • Chemical & Material Sciences (AREA)
  • Dispersion Chemistry (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Lubricants (AREA)

Abstract

La présente invention concerne un fluide de forage à base d'eau comprenant un fluide aqueux, un complexe oxydes métalliques mélangés/argile, et un suppresseur anionique, le suppresseur anionique comprenant un acide de Lewis et un lubrifiant et le lubrifiant comprenant un composé soufré et au moins un tampon, le ou les tampons étant en quantité suffisante pour obtenir un pH dans la plage allant d'environ 9 à 13.
PCT/US2010/031241 2009-04-15 2010-04-15 Lubrifiant pour boues à base d'eau et procédés d'utilisation associés WO2010121027A2 (fr)

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Application Number Priority Date Filing Date Title
CA2758778A CA2758778C (fr) 2009-04-15 2010-04-15 Lubrifiant pour boues a base d'eau et procedes d'utilisation associes

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US16960709P 2009-04-15 2009-04-15
US61/169,607 2009-04-15

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WO2010121027A2 true WO2010121027A2 (fr) 2010-10-21
WO2010121027A3 WO2010121027A3 (fr) 2011-01-20

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Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN109097004A (zh) * 2018-10-11 2018-12-28 河北硅谷化工有限公司 钻井液用抗高温降粘剂
US11095102B2 (en) 2016-09-06 2021-08-17 Quanta Associates, L.P. Repurposing pipeline for electrical cable

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN109135692A (zh) * 2018-10-11 2019-01-04 河北硅谷化工有限公司 钻井液用硅氟活性剂

Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3219580A (en) * 1962-04-26 1965-11-23 Phillips Petroleum Co Drilling fluids having enhanced lubricating properties
US4802998A (en) * 1986-07-08 1989-02-07 Henkel Kommanditgesellschaft Auf Aktien Powder-form lubricant additives for water-based drilling fluids
EP0770661A1 (fr) * 1995-10-27 1997-05-02 B W Mud Limited Lubrifiant pour boue de forage
WO2008118748A1 (fr) * 2007-03-23 2008-10-02 M-I L.L.C. Fluides de forage à base aqueuse pour applications à haute température et haute pression et leurs procédés d'utilisation

Patent Citations (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3219580A (en) * 1962-04-26 1965-11-23 Phillips Petroleum Co Drilling fluids having enhanced lubricating properties
US4802998A (en) * 1986-07-08 1989-02-07 Henkel Kommanditgesellschaft Auf Aktien Powder-form lubricant additives for water-based drilling fluids
EP0770661A1 (fr) * 1995-10-27 1997-05-02 B W Mud Limited Lubrifiant pour boue de forage
WO2008118748A1 (fr) * 2007-03-23 2008-10-02 M-I L.L.C. Fluides de forage à base aqueuse pour applications à haute température et haute pression et leurs procédés d'utilisation

Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US11095102B2 (en) 2016-09-06 2021-08-17 Quanta Associates, L.P. Repurposing pipeline for electrical cable
US11095101B2 (en) 2016-09-06 2021-08-17 Quanta Associates, L.P. Repurposing pipeline for electrical cable
CN109097004A (zh) * 2018-10-11 2018-12-28 河北硅谷化工有限公司 钻井液用抗高温降粘剂

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CA2758778A1 (fr) 2010-10-21
WO2010121027A3 (fr) 2011-01-20

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