WO1995024452A1 - Fluides de forage - Google Patents

Fluides de forage Download PDF

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Publication number
WO1995024452A1
WO1995024452A1 PCT/GB1995/000328 GB9500328W WO9524452A1 WO 1995024452 A1 WO1995024452 A1 WO 1995024452A1 GB 9500328 W GB9500328 W GB 9500328W WO 9524452 A1 WO9524452 A1 WO 9524452A1
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WO
WIPO (PCT)
Prior art keywords
fluid
formate
calcium
well
oil
Prior art date
Application number
PCT/GB1995/000328
Other languages
English (en)
Inventor
Eric Davidson
Original Assignee
Scotoil Services Ltd.
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
Application filed by Scotoil Services Ltd. filed Critical Scotoil Services Ltd.
Publication of WO1995024452A1 publication Critical patent/WO1995024452A1/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
    • C09K8/32—Non-aqueous well-drilling compositions, e.g. oil-based
    • C09K8/36—Water-in-oil emulsions
    • 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
    • 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
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/18—Bridging agents, i.e. particles for temporarily filling the pores of a formation; Graded salts

Definitions

  • Oil and gas well fluids are used in the drilling, completion and wor over of oil and gas wells.
  • Such oil and gas well fluids may be water-based and typical water-based well fluids are aqueous solutions of salts, particularly solutions of inorganic salts, especially halide salts, of alkali or alkaline earth metals.
  • Another type of oil and gas well fluid which is commonly used is a fluid which is based on an invert emulsion which comprises a two-phase system of an aqueous phase emulsified in an oil. e.g. an aqueous phase emulsified in diesei oil or kerosene.
  • the well fluid will have a density which is sufficiently high that the column of well fluid has a hydrostatic pressure which is greater than the pressure exerted by the fluid in the rock strata of interest.
  • the excess of the hydrostatic pressure over the pressure exerted by the fluid in the strata prevents fluid escaping from the strata.
  • this e.xcess of pressure tends to force the well fluid into the strata, which is undesirable.
  • Well fluids are usually required to have properties which restrict loss of the well fluid into the strata i.e. they have so-called fluid loss control properties. Thus. it is a common practice to include fluid loss control agents which restrict and'or prevent this loss of well fluid.
  • An alternative approach is to piace a smail volume of a well fluid with good fluid loss control properties, a so-called fluid loss piil. in the region of the well adjacent the exposed strata with the necessary hydrostatic pressure being provided by placing a clear dense unmodified brine on top of the piii.
  • fluid loss control agents include a combination of three components: i finely divided solid particles which bridge the throats of the pores of the permeable strata of interest and which are known as bridging agents ; ii polymers, e.g.. xanthan gum and hydroxyethyl cellulose which increase the viscosity of the well fluid and thus improve the suspension properties of the fluid; and iii conventional fluid loss polymers, e.g.. starch, modified starch or derivatised cellulose.
  • bridging agent Three types have been suggested: l Insoluble solids, e g bentonite or Danum sulphate Such solids suffer from the disadvantage that thev are insoluble in most solvents and solid particles remaining m the pores of the rock strata cannot be dissolved out This may permanently damage the permeability of the reservoir rock strata ⁇ Acid soluble paniculate materials, e g calcium carbonate or dolomite, are frequently used because thev can oe removed from the pores of the strata by subsequent acid treatment in Sized sodium chloride particles suspended in saturated sodium chloride bnne can be used as.
  • Oil-based oil and gas well fluids compnse a two-phase system of an aqueous phase emulsified in an oil.
  • aqueous phase emulsified in an oil.
  • the aqueous phase is usually calcium chlo ⁇ de or sodium chloride bnne.
  • the fluid contains wetting agents to bnng about emulsification of the aqueous phase and to ensure that rock cuttings and the exposed borehole face are maintained in an oil wet condition
  • a p ⁇ ncipal advantage of oil-based fluids is that they ensure that water sensitive rocks are always oil wet and therefore protected from the a ⁇ ueous ingredient
  • Other components which may be used in such oil-based fluids include organophilic clay, the function of which is to provide rheology, and weighting/ ridging agents are usuailv included in the form of finely divided banum sulphate or limestone.
  • the sait is affected by the dispersed aqueous phase. Observed effects included dissolution of the sait in the dispersed brine droplets, and a pronounced tendency for the salt panicles to grow.
  • the present invention is based on the discovery that calcium formate can be used very successfully as a soiid panicuiate material in oil and gas well fluids, that is in both aqueous-based and oil-based oil and gas well fluids.
  • European Patent Specification EP 0259939 B describes the use of formate salts as components of halide brine-based well fluids, especially sodium chloride based brines, in which the formate salt acts as a preservative for certain hydrocolloid polymers, but it does not refer to the use in fluids of formate salts in paniculate form.
  • the present invention provides an oil or gas well fluid which comprises a liquid phase having dispersed therein rineiy divided panicles of calcium and/or magnesium formate.
  • the oil or gas well fluid may comp ⁇ se an aqueous liquid phase, e.g.. an aqueous phase of a concentrated aqueous bnne or it may comprise an oil-based liquid phase for example an aqueous phase emulsified in an oil. e.g.. a concentrated aqueous brine emulsified in an oil such as diesei or kerosene.
  • the concentrated aqueous brine which may itself comprise the liquid phase of the oil or gas well fluid or which may be present in the fluid as an emulsion in an oil phase is a salt solution which has little or no tendency to dissolve the calcium and/or magnesium formate.
  • solubility of calcium and/or magnesium formate in the brine will typically be less than 20 g.l "1 and more usually less than 10 g.l "1 .
  • the brine can be a saturated solution of calcium or magnesium formate and in this case the solubi tv of the solid calcium or magnesium formate, which is effectively additional to the dissolved matenal in the bnne respectively is regarded as zero
  • the low solubihtv of the calcium and/or magnesium formate in the bnne can be met if the bnne shares a common ion with the dispersed solid
  • the bnne contains sufficient dissolved salt that the effective amount of water available to dissolve the suspended solid is sufficiently small that the dispersed solid does not have significant solubility in the bnne
  • the invention provides an oil or gas well fluid which comp ⁇ ses a concentrated aqueous brine including at least one dissolved alkali or alkaline earth metal formate having dispersed in the fluid finely divided particles of caicium and/or magnesium tormate
  • the invention further includes the use of calcium and/or magnesium formate as a paniculate solid in an oil or gas well fluid
  • Calcium formate is particularly userul in the fluids and m the methods of the invention and the use and/or inclusion of calcium formate forms a specific aspect of the invention
  • the invention included a well fluid of the invention which comp ⁇ ses a bnne wmch is a saturated a ⁇ ueous solution of calcium formate and m which the suspended solid is finely divided calcium formate
  • the bnne is formed from a salt or mixture of salts dissolved in water
  • tnat the sa ⁇ t(s) of the onne snare at least one common ion with the dispersed finely divided particles of calcium or magnesium formate
  • Well fluids of the invention having a common ion between the bnne and the dispersed solid form a particularly useful separate aspect of the invention
  • the salt forming the bnne can be a calcium salt, e g calcium nitrate, calcium chlo ⁇ de.
  • calcium bromide or combinations of these, e g calcium bromide and caicium nitrate Formate-based b ⁇ nes can also be used e g those based on alkali metal salts, e g caesium formate, rubidium formate, potassium formate and sodium formate or mixtures of such salts
  • Other b ⁇ nes e a a bnne based on sodium nitrate can also be used However, particularly where a low density fluid is required, it is verv useful to use a brine based on caicium formate, especially where the finely divided panicles are of calcium formate.
  • Calcium formate has a low temperature coefficient of solubility; its solubility is 16.2 g. per 100 ml water at 0°C and 1 S.4 g. per 100 ml water at 100°C. This low temperature coefficient of solubility contributes to the performance of calcium formate as a fluid loss control material. The smail fluctuation of solubility with temperature assists in the preservation of the particle size distribution and thus of the fluid loss control properties.
  • the natural pH of brines based on calcium formate or other brines containing suspended calcium formate is 7 to 8, although the presence of other acidic, basic or buffering species may alter the actual pH of a particular brine.
  • During drilling or completion operations it can be desirable to operate at somewhat higher values of pH. Commonly such increases of pH are achieved by adding readily soluble bases such as sodium hydroxide or carbonate.
  • readily soluble bases such as sodium hydroxide or carbonate.
  • calcium formate care is required if such alkalis are used as increasing the hvdroxvl or carbonate ion concentration can lead to precipitation of calcium hydroxide or carbonate.
  • magnesium hydroxide and/or carbonate as solid pow ⁇ ers to increase the pH
  • These magnesium bases can readily raise the pH of the bnne to a maximum of about 10.
  • Calcium formate is a particularly goo ⁇ paniculate matenal for use in formate brines
  • the h gh concentration of formate in solution generates a common ion effect further limiting any tendency of the calcium formate to dissolve
  • the commonality between the anions in the bnne ana the paniculate mate ⁇ ai greatly re ⁇ uces the chance of double decomposition reactions
  • calcium oromide and calcium nitrate/bromide b ⁇ nes the high concentrations of calcium m the b ⁇ nes means that the common ion effect suppresses ⁇ issolution of the caicium formate
  • the commonality between the bnne cation and the cation of the particulate material reduces any tendency for precipitation reactions
  • Sodium chlonde solids have the disadvantage that thev are incompatible with potassium formate b ⁇ nes and with calcium nitrate b ⁇ nes
  • a dense brine may be prepared from potassium formate, but concentrated solutions of potassium formate react with solid sodium chlo ⁇ de The double decomposition reaction gives rise to sodium formate which has a much lower solub
  • the finely divided calcium or magnesium formate is tvpicallv used in an amount of from 50 to 500, particularly 75 to 250 g 1 of the well fluid
  • the amount will be chosen to provide the desire ⁇ properties in the well fluid
  • the particle size of the finely divided solid calcium or magnesium formate will be chosen to suit the application Tvpicallv
  • the panicle size will be in the range 1 to 300 m pa ⁇ iculariv 1 to 75 urn
  • Fineiv divided solids, particularly of calcium or magnesium formate, which have a panicle size and/or size dist ⁇ bution which is selecte ⁇ for a specific purpose are referred to as sized solids
  • the well fluids of the invention can include other components commonly used in well fluids, such as viscosity improving agents otherwise known as thickening agents, polymers which confer ennanced fluid loss control, crystallisation modifiers or inhibitors and clav stabilisation additives
  • Viscositv improving agents are tvpicallv water-soluble polvmers which confer increased viscosity or pseu ⁇ oplasticitv on the fluid These include poiysaccnandes, e g starch, modified starch or xanthan gum, polymers of bacte ⁇ al o ⁇ g , e g succinoglycan. cellulose de ⁇ vatives. e g carbomethoxvcellulose or hvdroxvethylcellulose.
  • Fluid loss control agents are typically poiymers, for example starch, modified starches and/or de ⁇ vatised cellulose Crystallisation modifiers or inhibitors, e g phospnonates, polyacrvlates and other mate ⁇ als with similar effects can be included
  • Clay stabilisation additives include glycols. silicates and polyvinyl alcohol.
  • the well fluids of the invention can be used in a variety of ways in oil and gas well operations. These include using calcium formate brine-based systems including finely divided panicles of calcium and/or magnesium formate as a weighting material. Such fluids can be made with relatively low densities and afford saturated systems which extend the range of fluids available.
  • brine-based systems including finely divided particles of calcium and/or magnesium formate can be used in workover and completion methods in which the fluid is pumped down the well so that the solid particles are forced to bridge across the pore structure of the strata of the rock formation to block or seal the pores to enable operations to be carried out in the well whilst the rock formation is sealed from the well and subsequently dissolving the formate paniculate solids by passing a sub-saturated brine into the well to dissolve the panicles of calcium and/or magnesium formate thus reopening the pores of the rock formation.
  • the invention includes a method of conducting completion or workover operations on an oil or gas well by passing a well fluid into or through a permeable oil or gas-bearing rock stratum and which comprises: i pumping down the well to a position adjacent the oil or gas bearing stratum a well fluid having dispersed therein finely divided particles of calcium and/or magnesium formate: ii applying pressure to the well fluid to force the panicles of calcium and/or magnesium formate to bridge across the pores of the permeable stratum to reduce the permeability of the stratum: iii conducting completion and/or workover operations on the well; and iv subsequently removing the particles from the pores of the rock stratum by passing a well fluid which is undersaturated in respect of calcium and/or magnesium formate as appropriate over the stratum to dissolve the solid calcium and/or magnesium formate, thereby restoring the permeability of the stratum.
  • the well fluid comprises a saturated aqueous solution of an alkali or alkaline earth metal formate, especially calcium formate, having dispersed therein finely divided particles of calcium and/or magnesium formate, especially calcium formate.
  • Size ⁇ calcium formate - is paniculate calcium formate having a particle size range of from 1 to 100 um
  • Base Bnne B - is a saturated a ⁇ ueous so ⁇ ium formate solution containing 355 g i of so ⁇ ium formate ana having a ⁇ ensity of 1 32 g ml '
  • Base Bnne C - is a mixed sait bnne containing 609 g 1 ' caicium bromi ⁇ e ana 617 g 1 ' calcium nitrate and having a density of 1 8 g.mi '
  • Potassium formate D ⁇ ne - Base Bnne D - is a saturated a ⁇ ueous potassium formate solution containing 1209 g i of potassium formate and having a density of 1 57 g.ml '
  • Base Bnne E - is a mixe ⁇ salt bnne containing 770 g l 1 of caesium formate and 604 g 1 ' potassium formate and having a density of
  • Xanthan gum - is the ⁇ rv material obtained from Rhone Poulenc
  • Succmogiycan broth - is an aqueous broth of bacte ⁇ al Succinoglycan from Shell Chemicals having a concentration of about 10% w/v (ca. 100 g.l ')
  • the amount used is given as the approximate amount of the dry poiymer Modified starch (Mod. St.) - is a crossiinked etherified starch obtained from Chemstar Products Inc. of Minneapolis. USA.
  • Modified Cellulose (Mod. Cell.) - is a purified low viscosity oil field grade of ( polyanionic carboxymethyl cellulose from Akzo Chemie.
  • test method was carried out in a smail cylindrical steel pressure cell which can be sealed at both ends.
  • the closures at both the base and the top of the cell include vaives.
  • the base of the ceil was sealed, a very fine mesh sieve inserted and a bed of fine sand was built up on the sieve.
  • the sand bed simulates a permeable rock.
  • the void volume of the sand be.: was flooded with an inert fluid, e.g.. with oil or an appropriate brine and the cell was heated in a specially designed heating jacket until it attained the desired test temperature.
  • a well fluid to be tested was introduced into the cell above the sand bed (taking care not to disturb the surface of the bed), and the top closure of the cell was fitted.
  • the upper part of the cell was pressurised through the valve in the top closure.
  • the valve in the base closure was opened thus applying a pressure differential across the sand bed.
  • the pressure forced fluid into the sand bed which displaced the liquid which had been used to flood the pore volume of the sand bed.
  • the voiu e of liquid displaced from the bed is a direct measure of the invasion of the bed by the fluid under test.
  • a well fluid, with no fluid loss control properties runs straight through the cell and thus the lower the volume of fluid displaced the better the fluid loss control properties of the well fluid under test.
  • the volume of fluid displaced was a quantitative measure of the fluid loss control properties of the well fluid under test.
  • the cell was disassembled and the depth of the filter cake containing solid particulate material from the well fluid was measured as a further indication of the effectiveness of fluid loss control (the smaller the depth of the filter cake containing the solid paniculate material from the well fluid the more effective the fluid loss control).
  • Example 3 The well fluids of Examples i to 6 were made from Base Brines A, B, C, D and E described above to each of which was added sized particulate calcium formate.
  • the formulations of these well fluids are set out in Table 1 below.
  • Example 3 the succinoglycan was added as a broth (described above).
  • the quantity given in Table 1 is the amount of (notionally) dry polymer; the water in the broth is not explicitly stated in Table 1 but does reduce the density of the fluid somewhat.
  • the densities of the fluids were measured and the fluids were rested as described above
  • Table 2 The test results, indicating the volume of fluid displaced and the thickness of the bed of calcium formate formed on the sand bed are set out in Table 2 below.
  • test conditions were:
  • Step 3 To the fluid from step 2 there was added 52.3 ml of water and
  • step 3 To the fluid from step 3 there was added 3.0 g of Asphaltene based fluid loss agent (obtained from M.I. Drilling Fluids) and the fluid was mixed for 5 minutes on the Hamilton Beach mixer.
  • Asphaltene based fluid loss agent obtained from M.I. Drilling Fluids
  • Step 5 To the fluid from step 4 there was added
  • the fluid loss prope ⁇ y test as described above was repeated except that the test was carried out at a temperature of 80°C and. prior to use in the test, the fluid was stored at 30°C for 17 days in order to allow for equilibration of the fluid.
  • a sample of fluid was stores in an enclosed vessei within an oven in which the temperature was cycled for over 60 hours between ambient and 80°C for a total of 6 cycles. This cycling mimics the temperature conditions encountered by a fluid as it circulates round a borehole which is being drilled. Also temperature cycling is very conducive to particle growth and would be expected to accelerate the inherent growth tendencies, if any, of the calcium formate particles.

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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)
  • Oil, Petroleum & Natural Gas (AREA)
  • Colloid Chemistry (AREA)

Abstract

Un fluide de forage pour puits de pétrole ou de gaz comprend une phase liquide qui contient une dispersion de fines particules de formate de calcium et/ou de magnésium.
PCT/GB1995/000328 1994-03-07 1995-02-16 Fluides de forage WO1995024452A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB9404374A GB9404374D0 (en) 1994-03-07 1994-03-07 Drilling fluids
GB9404374.2 1994-03-07

Publications (1)

Publication Number Publication Date
WO1995024452A1 true WO1995024452A1 (fr) 1995-09-14

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Cited By (12)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0726302A1 (fr) * 1995-02-10 1996-08-14 Texas United Chemical Company, Llc. Fluides de forage à haute densité et faible teneur en solides
WO1996030460A1 (fr) * 1995-03-31 1996-10-03 Baker Hughes Incorporated Utilisation de particules de sel calibrees comme agent de pontage pour fluides a base d'huile
EP0786507A1 (fr) * 1995-08-08 1997-07-30 Texas United Chemical Company, Llc. Saumures de forage à caractéristiques rhéologiques améliorées
DE19609194A1 (de) * 1996-03-09 1997-09-11 Mi Drilling Fluids Int Bv Bohr- und Komplettierungsspülmittel
US5785747A (en) * 1996-01-17 1998-07-28 Great Lakes Chemical Corporation Viscosification of high density brines
EP0939072A1 (fr) * 1998-02-26 1999-09-01 Bayer Aktiengesellschaft Formiate de calcium en morceaux
EP0992563A1 (fr) * 1998-09-05 2000-04-12 Clariant GmbH Fluide de forage contenenat des carboxylates alcalins et présentant des propriétés anticorrosives
US6100222A (en) * 1996-01-16 2000-08-08 Great Lakes Chemical Corporation High density, viscosified, aqueous compositions having superior stability under stress conditions
US6632779B1 (en) 1999-01-07 2003-10-14 Bj Services Company, U.S.A. Wellbore treatment and completion fluids and methods of using the same
EP2181072A1 (fr) * 2007-08-02 2010-05-05 M-I Llc Récupération de saumures de formiate
EP2188490A1 (fr) * 2007-08-02 2010-05-26 M-I Llc Recyclage de saumures de formiate contaminées par halogénure
US7878246B2 (en) 2007-12-03 2011-02-01 Schlumberger Technology Corporation Methods of perforation using viscoelastic surfactant fluids and associated compositions

Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4175042A (en) * 1976-10-26 1979-11-20 Texas Brine Corporation Well completion and work over fluid and method of use
US4186803A (en) * 1976-10-26 1980-02-05 Texas Brine Corporation Well completion and work over method
JPS59193980A (ja) * 1983-04-19 1984-11-02 Dai Ichi Kogyo Seiyaku Co Ltd ボ−リング用泥水組成物
EP0259939A2 (fr) * 1986-09-12 1988-03-16 Shell Internationale Researchmaatschappij B.V. Compositions aqueuses de polysaccharides
GB2250761A (en) * 1990-12-06 1992-06-17 Shell Int Research Aqueous polysaccharide compositions and their use
EP0572113A1 (fr) * 1992-05-29 1993-12-01 BP Chemicals Limited Saumures aqueuses

Patent Citations (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4175042A (en) * 1976-10-26 1979-11-20 Texas Brine Corporation Well completion and work over fluid and method of use
US4186803A (en) * 1976-10-26 1980-02-05 Texas Brine Corporation Well completion and work over method
JPS59193980A (ja) * 1983-04-19 1984-11-02 Dai Ichi Kogyo Seiyaku Co Ltd ボ−リング用泥水組成物
EP0259939A2 (fr) * 1986-09-12 1988-03-16 Shell Internationale Researchmaatschappij B.V. Compositions aqueuses de polysaccharides
GB2250761A (en) * 1990-12-06 1992-06-17 Shell Int Research Aqueous polysaccharide compositions and their use
EP0572113A1 (fr) * 1992-05-29 1993-12-01 BP Chemicals Limited Saumures aqueuses

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
DATABASE WPI Derwent World Patents Index; AN 84-309787 *

Cited By (19)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0726302A1 (fr) * 1995-02-10 1996-08-14 Texas United Chemical Company, Llc. Fluides de forage à haute densité et faible teneur en solides
WO1996030460A1 (fr) * 1995-03-31 1996-10-03 Baker Hughes Incorporated Utilisation de particules de sel calibrees comme agent de pontage pour fluides a base d'huile
US5602083A (en) * 1995-03-31 1997-02-11 Baker Hughes Inc. Use of sized salts as bridging agent for oil based fluids
EP0786507A1 (fr) * 1995-08-08 1997-07-30 Texas United Chemical Company, Llc. Saumures de forage à caractéristiques rhéologiques améliorées
US6100222A (en) * 1996-01-16 2000-08-08 Great Lakes Chemical Corporation High density, viscosified, aqueous compositions having superior stability under stress conditions
US5785747A (en) * 1996-01-17 1998-07-28 Great Lakes Chemical Corporation Viscosification of high density brines
DE19609194A1 (de) * 1996-03-09 1997-09-11 Mi Drilling Fluids Int Bv Bohr- und Komplettierungsspülmittel
EP0939072A1 (fr) * 1998-02-26 1999-09-01 Bayer Aktiengesellschaft Formiate de calcium en morceaux
US6350779B1 (en) 1998-02-26 2002-02-26 Bayer Aktiengesellschaft Piece-form calcium formate
EP0992563A1 (fr) * 1998-09-05 2000-04-12 Clariant GmbH Fluide de forage contenenat des carboxylates alcalins et présentant des propriétés anticorrosives
US6239081B1 (en) 1998-09-05 2001-05-29 Clariant Gmbh Alkali-metal-carboxylate-containing drilling fluid having improved corrosion properties
US6632779B1 (en) 1999-01-07 2003-10-14 Bj Services Company, U.S.A. Wellbore treatment and completion fluids and methods of using the same
EP2181072A1 (fr) * 2007-08-02 2010-05-05 M-I Llc Récupération de saumures de formiate
EP2188490A1 (fr) * 2007-08-02 2010-05-26 M-I Llc Recyclage de saumures de formiate contaminées par halogénure
EP2181072A4 (fr) * 2007-08-02 2011-08-24 Mi Llc Récupération de saumures de formiate
EP2188490A4 (fr) * 2007-08-02 2011-11-30 Mi Llc Recyclage de saumures de formiate contaminées par halogénure
US8344179B2 (en) 2007-08-02 2013-01-01 M-1 L.L.C. Reclamation of halide-contaminated formate brines
US8871097B2 (en) 2007-08-02 2014-10-28 M-I L.L.C. Reclamation of formate brines
US7878246B2 (en) 2007-12-03 2011-02-01 Schlumberger Technology Corporation Methods of perforation using viscoelastic surfactant fluids and associated compositions

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Publication number Publication date
GB9404374D0 (en) 1994-04-20

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