EP1694797A1 - Fluides de forage a base d'eau faisant appel a des additifs de latex - Google Patents

Fluides de forage a base d'eau faisant appel a des additifs de latex

Info

Publication number
EP1694797A1
EP1694797A1 EP04779758A EP04779758A EP1694797A1 EP 1694797 A1 EP1694797 A1 EP 1694797A1 EP 04779758 A EP04779758 A EP 04779758A EP 04779758 A EP04779758 A EP 04779758A EP 1694797 A1 EP1694797 A1 EP 1694797A1
Authority
EP
European Patent Office
Prior art keywords
water
drilling fluid
based drilling
providing
latex
Prior art date
Legal status (The legal status 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 status listed.)
Withdrawn
Application number
EP04779758A
Other languages
German (de)
English (en)
Inventor
Calvin J. Ii Stowe
Ronald G. Bland
Dennis Clapper
Tao Xiang
Saddok Benaissa
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Baker Hughes Holdings LLC
Original Assignee
Baker Hughes Inc
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 US10/634,334 external-priority patent/US7393813B2/en
Application filed by Baker Hughes Inc filed Critical Baker Hughes Inc
Publication of EP1694797A1 publication Critical patent/EP1694797A1/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/04—Aqueous well-drilling compositions
    • C09K8/06—Clay-free compositions
    • C09K8/12—Clay-free compositions containing synthetic organic macromolecular compounds or their precursors
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/04—Aqueous well-drilling compositions
    • C09K8/14—Clay-containing compositions
    • C09K8/18—Clay-containing compositions characterised by the organic compounds
    • C09K8/22—Synthetic organic compounds
    • C09K8/24—Polymers
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
    • C09K8/504—Compositions based on water or polar solvents
    • C09K8/506—Compositions based on water or polar solvents containing organic compounds
    • C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds

Definitions

  • Drilling fluids used in the drilling of subterranean oil and gas wells as well as other drilling fluid applications and drilling procedures are known.
  • drilling fluids also known as drilling muds, or simply "muds".
  • the drilling fluid is expected to carry cuttings up from beneath the bit, transport them up the annulus, and allow their separation at the surface while at the same time the rotary bit is cooled and cleaned.
  • a drilling mud is also intended to reduce friction between the drill string and the sides ofthe hole while maintaining the stability of uncased sections of the borehole.
  • the drilling fluid is formulated to prevent unwanted influxes of formation fluids from permeable rocks penetrated and also often to form a thin, low permeability filter cake which temporarily seals pores, other openings and formations penetrated by the bit.
  • the drilling fluid may also be used to collect and interpret information available from drill cuttings, cores and electrical logs. It will be appreciated that within the scope ofthe claimed invention herein, the term "drilling fluid” also encompasses "drill-in fluids”.
  • Drilling fluids are typically classified according to their base material. In water-based muds, solid particles are suspended in water or brine. Oil can be emulsified in the water or brine. Nonetheless, the water is the continuous phase. Oil-based muds are the opposite.
  • Oil- based muds that are water-in-oil emulsions are also called invert emulsions.
  • Brine-based drilling fluids are a water-based mud in which the aqueous component is brine.
  • Optimizing high performance water base mud design is commonly at the forefront of many drilling fluid service and oil operating companies' needs due to the various limitations of invert emulsion fluids.
  • Invert emulsion fluids formulated with traditional diesel, mineral or the newer synthetic oils are the highest performing drilling fluids with regard to shale inhibition, borehole stability, and lubricity.
  • Various limitations of these fluids such as environmental concerns, economics, lost circulation tendencies, kick detection, and geologic evaluation concerns maintains a strong market for high performance water based fluids. Increased environmental concerns and liabilities continue to create an
  • Reducing drilling fluid pressure invasion into the wall of a borehole is one of the most important factors in maintaining wellbore stability. It is recognized that sufficient borehole pressure will stabilize shales to maintain the integrity of the borehole.
  • a water-based drilling fluid including water and a polymer latex capable of providing a deformable latex film or seal on at least a portion of a subterranean formation.
  • FIG. 1 shows a chart of the formation pressure as a function of time for a pressure invasion test using various intermediate test formulations
  • FIG.2 is a graph ofthe surfactant effect on GENCAL 7463 particle size in 20% NaCI/1 lb/bbl (2.86 g/l) NEWDRILL PLUS/1 Ib/bbl (2.86 g/l) XAN-PLEX
  • FIG. 3 is a graph ofthe influence of polymer resins (3 Ib/bbl, 8.58 g/l) on
  • FIG.4 is a graphical comparison ofthe effects on mud properties for EXP-
  • FIG.5 is a graph of PPT test results for ALPLEX, EXP-154/EXP-155, and
  • FIG. 6 is a graph showing the effect of circulation on EXP-154/EXP-155 mud performance
  • FIG. 7 is a graph showing the effect of latex on mud properties in 9.6 lb/gal (1 J 5 kg/l) 20% NaCl fluid after 16 hours, 250°F (121 °C) hot roll; the base fluid was 20% NaCI/1 lb/bbl (2.86 g/l) XAN-PLEX D/0.4 lb/bbl (1.14 g/l) NEW-
  • FIG.8 is a graph showing the effect of latex on mud properties in 12 lb/gal (1.44 kg/I) after hot rolling for 16 hours at 250°F (121 °C); the base fluid was 20% NaCI/0.75 lb/bbl (2.15 g/l) XAN-PLEX D/0.4 lb/bbl (1.14 g/l) NEW-DRILL PLUS/3 lb/bbl (8.58 g/l) BIO-PAQ/5 lb/bbl (14.3 g/l) EXP-154/150 Ib/bbl (429 g/l) MIL- CARB/27 Ib/bbl (77.2 g/l) Rev Dust;
  • FIG. 9 is a graph of 96 hour Mysidopsis bahia range-finder results for experimental products in 12 lb/gal (1.44 kg/I) fluids where the base fluid is 20% NaCI/0.5 lb/bbl (1.43 g/l) XAN-PLEX D/0.4-1 lb/bbl (1 J 4-2.86 g/l) NEW-DRILL PLUS/2 lb/bbl (5.72 g/l) MIL-PAC LV (or BIO-PAQ)/150 lb/bbl (429 g/l) MIL-BAR; [0024] FIG.
  • FIG. 10 is a graph of high temperature high pressure (HTHP) fluid loss rate on 50 mD cement disk for the mud containing 3% latex polymer after being hot rolled at 250°F for 16 hours; and [0025]
  • FIG. 11 is a photograph of an internal filter cake formed using the method of the present invention.
  • a polymer latex added to a water-based drilling fluid can reduce the rate the drilling fluid pressure invades the borehole wall of a subterranean formation during drilling.
  • the polymer latex preferably is capable of providing a deformable latex film or seal on at least a portion of a subterranean formation.
  • film or “seal” are not intended to mean a completely impermeable layer.
  • the seal is considered to be semi-permeable, but nevertheless at least partially blocking of fluid transmission sufficient to result in a great improvement in osmotic efficiency.
  • a submicron polymer latex added to a high salt water-based mud containing an optional, but preferred combining/precipitating agent, such as an aluminum complex will substantially reduce the rate of mud pressure penetration into shale formations.
  • the pressure blockage, reliability, magnitude and pore size that can be blocked are all increased by the latex addition. Inhibiting drilling fluid pressure invasion into the wall of a borehole is one of the most important factors in maintaining wellbore stability.
  • the essential components of the water-based drilling fluids of this invention are the polymer latex and water, which makes up the bulk of the fluid. Of course, a number of other common drilling fluid additives may be employed as well to help balance the properties and tasks of the fluid.
  • the polymer latex is preferably, but not limited to a carboxylated styrene/butadiene copolymer or a sulfonated styrene/butadiene copolymer.
  • a particular, non-limiting carboxylated styrene/butadiene copolymer is GENCAL 7463 available from Omnova Solution Inc.
  • a particular, non-limiting sulfonated styrene/butadiene copolymer is GENCEAL 8100 also available from Omnova Solution Inc.
  • Other suitable polymer latexes include, but are not limited to polymethyl methacrylate, polyethylene, polyvinylacetate copolymer, polyvinyl acetate/vinyl chloride/ethylene copolymer, polyvinyl acetate/ethylene copolymer, natural latex, polyisoprene, polydimethylsiloxane, and mixtures thereof.
  • a somewhat less preferred polymer latex is polyvinylacetate copolymer latex, more specifically, an ethylenevinyl chloride vinylacetate copolymer.
  • polyvinylacetate copolymer latices will perform within the methods of this invention, they generally do not perform as well as the carboxylated styrene/butadiene copolymers.
  • the average particle size of the polymer latex is preferably less than 1 micron or submicron and most preferably having a diameter of about 0.2 microns or 0.2 microns or less. Other polymers in the disperse phase may be found to work. It is anticipated that more than one type of polymer latex may be used simultaneously.
  • the proportion of the polymer latex in the drilling mud, based on the total amount ofthe fluid may range from about 0J to about 10 vol.%, preferably from about 1 to about 8 vol.%, and most preferably from about 2 to about 5 vol.%.
  • the sulfonated latexes ofthe present invention have an added advantage in that they can often be used in the absence of a surfactant. This can simplify the formulation and transportation ofthe drilling fluid additives to production sites. This can also reduce costs in some applications. In applications of drilling in depleted sands, there is often no need of a precipitating agent. In the depleted sands applications, there is also often no need of a surfactant for carboxylated styrene/butadiene copolymers for fresh water applications.
  • the optional salt may be any common salt used in brine-based drilling fluids, including, but not necessarily limited to calcium chloride, sodium chloride,
  • potassium chloride magnesium chloride, calcium bromide, sodium bromide, potassium bromide, calcium nitrate, sodium formate, potassium formate, cesium formate and mixtures thereof.
  • a “high salt content” is meant at least 20 weight percent, and saturated brine solutions are preferred in one non-limiting embodiment. It will appreciated that it is impossible to predict in advance what the salt content of a particular saturated brine solution will be since the saturation point depends on a number of factors including, but not limited to the kinds and proportions of the various components of the water-based fluid.
  • the salt is optional because the invention will perform without it, that is, using fresh water. [0031] Another optional component is precipitating agent.
  • Suitable precipitating agents include, but are not limited to, silicates, aluminum complexes, and mixtures thereof.
  • Suitable aluminum complexes include, but are not limited to, sodium aluminate, NaAI 2 O 2 , sometimes written as Na 2 OAI 2 O 3 , aluminum hydroxide, aluminum sulfate, aluminum acetate, aluminum nitrate, potassium aluminate, and the like, and mixtures thereof (especially at pH of >9 for these compounds to be soluble in water).
  • the proportion of the precipitating agent in the drilling mud, based on the total amount of the fluid may range from about 0.25 to about 20 lb/bbl (about 0.71 to about 57.2 g/l), preferably from about 1 to about 10 lb/bbl (about 2.86 to about 28.6 g/l) and most preferably from about 2 to about 7 lb/bbl (about 5.72 to about 20 g/l).
  • the precipitating agent is believed to chemically bound to the surface of the clay of the borehole and provide a highly active polar surface.
  • Another optional component of the composition of the i nvention i s a surfactant.
  • the surfactant treated latex wets the surface strongly and accumulates to form a film or coating that seals fractures and defects in the shale.
  • Suitable wetting surfactants include, but are not limited to, betaines, alkali metal alkylene acetates, sultaines, ether carboxylates, and mixtures thereof. It has been determined that surfactants are particularly beneficial when salts are present in the drilling fluid, and are not as preferred in fresh water fluid systems.
  • the proportions of these components based on the total water-based drilling fluid are from about 0J to 10 volume% of polymer latex, at least 1 wt % of salt (if present), from about 0.25 to 20 lb/bbl (about 0.71 to about 57.2 g/l) of precipitating agent (if present), from about 0.005 to about 2 vol.% of surfactant (if
  • the balance being water.
  • the proportions range from about 1 to 8 vol.% of polymer latex, at least 1 wt % of salt (if present), from about 1 to 10 lb/bbl (about 2.86 to about 28.6 g/l) of precipitating agent (if present) from about 0.01 to about 1.75 vol. % of wetting surfactant (if present), the balance being water.
  • the sodium aluminate or other precipitating agent be in a metastable form in the mud, which means that it is in suspension or solution, but precipitates out upon the borehole wall.
  • aluminum compounds have been added to the mud on site. If added to mud formulations earlier, they tend to be unstable and precipitate prematurely.
  • the pore pressure transmission (PPT) device is based on a 1500 psi (10,300 kPa) Hassler cell designed for 2.5cm diameter core plugs from 2.5cm to 7.5cm in length.
  • a Hassler cell is a cylinder with a piston inserted in each end. The core is held between the two pistons.
  • a rubber sleeve is placed around the core and the pistons to seal around the core and prevent flow around the core. The outside of the sleeve is pressured to make a good seal.
  • the low pressure side of the core (formation side) is fitted with a 1 liter, 2000 psi. (13,800 kPa), stainless steel accumulator to provide back pressure.
  • the high pressure side ofthe core is connected to two similar accumulators, one for pore fluid, and one for the test fluid.
  • the pressure in each accumulator is controlled with a manual regulator fed by a 2200 psi (15,200 kPa) nitrogen bottle.
  • All pressures are monitored with Heise transducers. The transducer pressures are automatically computer logged at preset intervals.
  • the cell is enclosed in an insulated chamber and the temperature maintained with a 200 watt heater.
  • the heater is controlled with a Dwyer temperature controller driving a Control Concepts phase angle SCR control unit. Temperature control is accurate to +/- 0.05 °C. [0045] A pressure is applied to one end of the core and the flow through the core is measured. The piston on the low pressure side is filled with liquid, and blocked, so an increase in liquid pressure is measured rather than flow. A very small amount of liquid flow through the core will make a large rise in the
  • 154-23110-CIP 9 pressure making the cell sensitive enough to measure flow through shale.
  • Shale has a very low permeability, so the flow of fluid through it is very small.
  • Pressure is plotted versus time. Results are expressed as formation pressure (FP). If the FP increases overtime, there is pressure penetration; if the formation pressure decreases over time there is not, and the latter is what is desired.
  • Example 1 The fluid of Example 1 was used. Three 50% displacements of 50 cc each were performed during and just after heating up of the test cell. One run was started at 100% displacement and the temperature was difficult to control, so it was decided starting at 50% was better.
  • EXP-153 is a sulfonated polymer resin used to control HTHP fluid loss in this system.
  • EXP-154 is considered an alternative to aluminum complex product ALPLEX. Compared to ALPLEX, EXP-154 exhibits much better compatibility with latex fluids.
  • EXP-155 is a modified latex product. Compared to other commercially available latices EXP-155 displays less sensitivity to electrolytes and does not flocculate in 20% sodium chloride fluids at temperatures up to 300°F (149°C).
  • the shale inhibition characteristics were determined by shale dispersion tests that included static wafer test, and pore pressure (PPT) tests.
  • PPT pore pressure
  • Example 2 The circumference ofthe shale and pistons are sealed with a rubber sleeve.
  • the plug i s oriented with the bedding planes i n the parallel or high permeability direction.
  • Drilling fluid at 300 psi (2,070 kPa) is displaced through the upstream piston (borehole side) and seawater at 50 psi (345 kPa) is displaced through the downstream piston (formation side).
  • the seawater in the downstream piston is contained with a valve. As mud filtrate enters the borehole end ofthe plug, connate water in the shale is displaced into the formation piston.
  • latex As noted above, initial experiments indicated that some latex products (emulsion polymers) produced synergistic effects with an aluminum complex, resulting in improved pore pressure transmission characteristics of the fluids. This result revealed a new approach to the design of highly inhibitive, water- based fluids.
  • latex is generally considered to be a metastable system. The large surface of the particles is thermodynamically unstable and any perturbation affecting the balancing forces stabilizing the polymer dispersion
  • 154-23110-CIP 16 influenced by ALPLEX. Those particles greater than 100 microns in the fluid containing ALPLEX may have partially resulted from insoluble lignite (a component of ALPLEX). A similar effect was also observed with GENCAL 7463. Poor solubility and slow dissolution rate ofthe lignite in high salt concentrations is probably the main factor contributing to decreased latex stability.
  • FIG. 3 shows the effects of different polymer resins on the particle size distributions of EXP-155.
  • EXP-153 exhibited the best compatibility with this latex system.
  • a new aluminum complex product, EXP-154 (a blend of 45% NaAIO 2 , 45% EXP-153 and 10% sodium D-gluconate) was invented for the latex system.
  • FIG.4 compares the effects on the mud properties for EXP-154 with ALPLEX in 12 lb/gal (1.44 kg/I) 20% NaCI/NEW-DRILL/EXP-155 fluids.
  • the experimental aluminum complex exhibits improved compatibility with latex and biopolymers.
  • EXP-154 is found to control filtration, both API and HTHP, better than does ALPLEX.
  • the seawater in the downstream piston is contained with a valve. As mud filtrate enters the borehole end of the plug, connate water in the shale is displaced into the formation piston. This additional water compresses the water inside the piston causing the pressure to rise. The pressure increase in the formation piston water is measured as formation pressure (FP) rise.
  • FP formation pressure
  • EXP-154/EXP- 155 fluid produces the best PPT results to date as shown in FIG. 5.
  • the top curve is a standard salt/polymer. The next one down is
  • EXP-154/AIRFLEX 728 formulation below that is the EXP-154/EXP-155 formulation, and finally at the bottom is a 80/20 ISOTEQ fluid, 25% CaCI 2 , 6 ppb (17.2 g/l) CARBO-GEL, and 10 ppb (28.6 g/l) OMNI- MUL.
  • the superior performance ofthe EXP-154/EXP-155 fluid is believed to be due, at least in part, to its small particle size.
  • GENCAL 7463 was more efficiently dispersed by the EXP-152 resulting in a much greater percentage of particles smaller than one micron.
  • EXP-155 Another characteristic of EXP-155 is that its ultra-fine particles are elastomer-like over a wide range of temperatures. When subjected to differential hydraulic pressure, these ultra-fine particles do not shear or break, but deform and penetrate the hairline fractures and to form an impermeable seal. At the temperatures between T g (glass transition temperature) and T m (melting point), most polymers will exhibit rubberlike elasticity. The glass transition temperature of EXP-155 is 52° F (11 °C). From the relationship between T g and T m plotted by Boyer, 1963, reproduced in Billmeyer, Textbook of Polymer Science, Second Edition, Wiley-lnterscience, New York, 1971, p.
  • T m of EXP-155 is about 300°F (422°K). This temperature range covers most applications in drilling fluids.
  • Circulation of the fluid was found to be an important element of the latex plugging mechanism. This was explored in the tests with EXP-155. As the formulation was only 1.5% latex particles by volume (EXP-155 is 50% active), insufficient latex was available in the mud to produce plugging u nder static conditions. With circulation, however, the latex accumulated on the surface and formed a plugging film. Standard procedure is to circulate the mud about 7 hours
  • Latex A 8:1 blended AIRFLEX 728 and EXP-152
  • EXP-155 8:1 blended GENCAL 7463 and EXP-152
  • FIGS. 7 and 8 The effects of adding 3% by volume of these latex products are illustrated in FIGS. 7 and 8.
  • latex p olymers contain deformable colloidal p articles, it can provide an excellent bridging and sealing ability to reduce the permeability of the formation where the lost circulation of drilling fluids may encountered.
  • Table III shows a typical formulation for testing the sealing ability of latex polymers on permeable formation. Without latex polymer, the fluid loss of this mud is out control. However, an addition of 3% of a vinyl acetate/ethylene/vinyl chloride latex polymer, available under the trade designation Airflex 728, into this mud results in the fluid loss decreasing sharply with time as shown in Figure 10.
  • Tables IV-VI display the data for Figure 10.
  • Figure 11 shows the section picture of a broken 50 milliDarcy (mD) disk after testing for four hours at 300°F with the fluid containing 3% latex polymer.
  • DFE-245 is an admixture of GenCal 7463 and Mirataine BET-O30 at a volume ratio of about 9:1. It can be clearly observed that the internal filter cake was formed inside of the 50 mD disk.
  • AIRFLEX 728 A polyvinylacetate latex (more specifically, an ethylenevinyl chloride vinylacetate copolymer ⁇ dispersion sold by Air Products.
  • AqS Abbreviation for AQUACOL-S a glycol available from Baker Hughes INTEQ.
  • BIO-LOSE Derivatized starch available from Baker Hughes INTEQ.
  • BIOPAQ Derivatized starch fluid loss additive available from Baker Hughes INTEQ.
  • ELVACE 40722-00 Vinylacetate/ethylene copolymer latex available from Reichhold.
  • EXP-153 Sulfonated polymer resin (or sulfonated humic acid with resin) available from Baker Hughes INTEQ.
  • EXP-154 A mixture of 45% NaAIO 2) 45% EXP-153 and 10% sodium D-gluconate.
  • EXP-155 An 8:1 volume blend of GENCAL 7463 and EXP- 152.
  • MIL-BAR Barite weighting agent available from Baker Hughes INTEQ.
  • MIL-CARB Calcium carbonate weighting agent available from Baker Hughes INTEQ.
  • MILPAC LV Low viscosity polyanionic cellulose available from Baker Hughes INTEQ (sometimes abbreviated as PacLV).
  • MAX-PLEX An aluminum complex for shale stability available from Baker Hughes INTEQ.
  • SYNTHEMUL CPS 401 Carboxylated acrylic copolymer available from Reichhold.
  • TYCHEM 68710 Carboxylated styrene/butadiene copolymer available from Reichhold.
  • TYLAC 68219 Carboxylated styrene/butadiene copolymer available from Reichhold.
  • TYLAC CPS 812 Carboxylated styrene/butadiene copolymer available from Reichhold.

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  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Dispersion Chemistry (AREA)
  • Compositions Of Macromolecular Compounds (AREA)
  • Lubricants (AREA)
  • Sealing Material Composition (AREA)
  • Earth Drilling (AREA)

Abstract

L'invention a trait à un fluide de forage à base d'eau, qui contient un latex polymère pouvant former un film de latex déformable sur au moins une partie d'une formation souterraine. Ledit fluide de forage permet de réduire la pénétration de pression lorsqu'il est utilisé pour forer des formations schisteuses dans le cadre d'opérations d'extraction d'hydrocarbures. On utilise de préférence, en conjonction avec le polymère, un agent de précipitation, tel qu'un silicate ou un complexe d'aluminium (par ex., de l'aluminate de sodium). En général, l'eau présente contient un sel permettant de former une saumure, souvent à saturation, bien que l'invention puisse être mise en oeuvre avec de l'eau douce. Si l'on emploie un sel, il est souvent utile de recourir également à un tensioactif, comme de la bétaïne.
EP04779758A 2003-07-31 2004-08-02 Fluides de forage a base d'eau faisant appel a des additifs de latex Withdrawn EP1694797A1 (fr)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US49168503P 2003-07-31 2003-07-31
US10/634,334 US7393813B2 (en) 2000-06-13 2003-08-04 Water-based drilling fluids using latex additives
PCT/US2004/024804 WO2005012456A1 (fr) 2003-07-31 2004-08-02 Fluides de forage a base d'eau faisant appel a des additifs de latex

Publications (1)

Publication Number Publication Date
EP1694797A1 true EP1694797A1 (fr) 2006-08-30

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EP (1) EP1694797A1 (fr)
AU (1) AU2004262024B2 (fr)
BR (1) BRPI0413078A (fr)
CA (1) CA2534080C (fr)
NO (1) NO344585B1 (fr)
WO (1) WO2005012456A1 (fr)

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EP1923369A1 (fr) 2006-11-17 2008-05-21 Elotex AG Mélange sec pour la cimentation des puits de forage.
GB0817501D0 (en) 2008-09-24 2008-10-29 Minova Int Ltd Method of stabilising a blasthole
CN101787265B (zh) * 2010-03-11 2012-12-19 中国石油集团川庆钻探工程有限公司 水基钻井液用无荧光润滑剂
CN108384519A (zh) * 2018-04-24 2018-08-10 中国石油集团渤海钻探工程有限公司 一种钻井液用乳胶类润滑防塌剂
US10577300B2 (en) 2018-06-12 2020-03-03 Saudi Arabian Oil Company Synthesis of sodium formate and drilling fluid comprising the same

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US6703351B2 (en) * 2000-06-13 2004-03-09 Baker Hughes Incorporated Water-based drilling fluids using latex additives

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Title
See references of WO2005012456A1 *

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WO2005012456A1 (fr) 2005-02-10
CA2534080C (fr) 2011-07-12
BRPI0413078A (pt) 2006-10-03
AU2004262024A1 (en) 2005-02-10
WO2005012456B1 (fr) 2005-05-19
CA2534080A1 (fr) 2005-02-10
AU2004262024B2 (en) 2010-08-12
NO20060217L (no) 2006-01-16
NO344585B1 (no) 2020-02-03

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