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WO1999036668A1 - Traitement de puits - Google Patents

Traitement de puits Download PDF

Info

Publication number
WO1999036668A1
WO1999036668A1 PCT/GB1998/003863 GB9803863W WO9936668A1 WO 1999036668 A1 WO1999036668 A1 WO 1999036668A1 GB 9803863 W GB9803863 W GB 9803863W WO 9936668 A1 WO9936668 A1 WO 9936668A1
Authority
WO
WIPO (PCT)
Prior art keywords
particles
beads
solution
inhibitor
concentration
Prior art date
Application number
PCT/GB1998/003863
Other languages
English (en)
Inventor
Philip John Charles Webb
Original Assignee
Aea Technology Plc
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 Aea Technology Plc filed Critical Aea Technology Plc
Priority to AU17723/99A priority Critical patent/AU1772399A/en
Publication of WO1999036668A1 publication Critical patent/WO1999036668A1/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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/92—Compositions for stimulating production by acting on the underground formation characterised by their form or by the form of their components, e.g. encapsulated material
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping

Definitions

  • This invention relates to a method for treating an oil or gas well with oil field chemicals such as scale inhibitors, the chemicals being in a solid form on or in particles of insoluble material, to particles suitable for use in such a method, and to a method of making such particles.
  • porous particles to introduce oil field chemicals into a well is known for example from GB 2 284 223 A, and from GB 2 298 440 A.
  • the particles might be used in the form of a pre-packed screen, or might be used in a gravel packing process, or in a formation fracturing process. Such a process has been proposed in particular for introducing scale inhibitor.
  • a method for making particles suitable for such use, but which need not be porous, is described in WO98/40606.
  • a method of making particles suitable for treating an oil or gas well wherein particles of an insoluble, inorganic material are wetted with a first solution comprising a well treatment agent in a solvent, the wetted particles are dried, the dried particles are then contacted with a second solution containing polyvalent cations at a high concentration, and the particles are then dried again.
  • the cations in the second solution might be divalent, such as calcium ions, or trivalent, such as ferric ions.
  • the concentration of the ions is preferably between 0.1 M and 5.0 M, for example between 2.0 M and 4.0 M.
  • the quantity (number of moles) of the polyvalent cations in the second solution is preferably between 5 and 20 times the quantity (number of moles) of the deposited well treatment agent in the particles. For example for phosphonate scale inhibitor this mole ratio is preferably about 10:1, while for polymer type scale inhibitors it is preferably about 20:1.
  • the volume of the second solution is preferably no more than that needed to wet the surfaces of the particles, for example about 0.36 ml of solution per gram of particles; the volume might be between 0.1 ml/g and 0.5 ml/g. If larger volumes of the second solution were to be used then there would be a greater degree of dissolution of the deposited well treatment agent, leading to formation of a less- adherent deposit.
  • the aim is to modify the solubility of the deposited well treatment agent without changing its adherent character.
  • the second solution is preferably an aqueous solution.
  • the particles are preferably of a ceramic material, of generally spherical shape, and if they are porous they are preferably of porosity no more than about 30 percent, for example in the range 10 percent to 20 percent. They are typically of size between about 0.3 mm to 5.0 mm, more preferably between 0.5 mm and 2.0 mm for example 1.0 mm. They may be supplied into the well packed into a pre-packed screen in the form of a filter bed, or may be used as a gravel pack within the oil well and the perforations, or alternatively if the particles are sufficiently strong they may be used as fracture proppants in a fracture process and thereby be injected into cracks in the formation extending away from the well bore. The treated particles may be used on their own, or may be mixed with other particles which may be non-porous or may be porous and contain other oil field chemicals.
  • the particles preferably comply with the standards set out in the API recommended practices for testing for gravel material, or those for proppant material
  • the particles may be further coated with a polymer or resin coating, which will modify the rate of dissolution.
  • Figure 1 shows graphically, on a linear scale for concentration, the release of a scale inhibitor from particles made according to the invention, compared to those made by a known process;
  • Figure 2 shows graphically, on a logarithmic scale for concentration, the same comparison as in figure 1 but for a considerably longer time scale.
  • the fluid injected into the rocks may contain a dissolved polymer which may be cross-linked to form a gel (so it is of high viscosity) , and may include particles of solid material such as sand grains or ceramic spheres which are carried into the fractures by the injected fluid. When the pressure is reduced the particles prevent the fractures closing. Such particles may be referred to as proppant particles.
  • the fractures may extend as much as 20 m or even 50 m or more out from the well bore, and the proppant particles will be distributed throughout the length of each fracture.
  • a gravel pack This consists of a filter bed of small particles filling all the space between a tubular fluid-permeable screen within the well bore, and the wall of the well, and extending into the perforations, the particles preferably being between 5 and 6 times larger than the sand particles whose inflow is to be prevented.
  • Such particles are usually referred to as gravel, although they may be substantially identical to those referred to as proppants; as a general rule particles for use as gravel do not have to be as strong as those for use as proppants.
  • the particles for use in such gravel pack or fracture processes may be ceramic beads of generally spherical shape, for example of diameter 0.7 mm, and of porosity 15 percent.
  • the beads can be impregnated with a scale inhibitor by substantially the same procedure as that described in GB 2 298 440 A, as follows:
  • concentrated scale inhibitor is made from a commercially-available diethylene-triamine penta- (methylenephosphonic acid) -based scale inhibitor (initially about 25 percent active material) , by first adding to this inhibitor 5 000 to 25 000 ppm cations (calcium and magnesium) added as chlorides, preferably 12 000 to 25 000 ppm, and then distilling under vacuum to about half the initial volume.
  • the scale inhibitor may be referred to as DTPMP.
  • the pH is adjusted to a value in the range pH 6.0 to pH 11.0 by adding concentrated sodium hydroxide, preferably to pH 10.
  • the ceramic beads are placed in a pressure vessel, and the vessel evacuated to about 0.1 mbar (10 Pa) absolute to ensure no air or vapours remain in the pores.
  • the vessel is then filled under vacuum with the concentrated inhibitor. After quarter of an hour the vacuum is released, the vessel drained, and the wet beads removed.
  • the wet beads are then dried in an oven or a fluidised bed.
  • the impregnated particles are then subjected to two further steps:
  • the dried beads are then contacted with a small volume of an aqueous solution of calcium chloride containing 100 grams per litre of calcium ions (2.5 M of calcium ions) , the volume of the solution being just sufficient to wet the surfaces of the beads.
  • the volume of solution is about 18 ml to wet 100 ' g of the dried beads .
  • the wetted beads are then dried by heating in a rotary drier or an oven at 120°C.
  • the treatment solution of step (iv) may differ from that described above for example containing a different polyvalent cation such as iron, or chromium, or aluminium; and the concentration of the polyvalent cations may differ from that specified above for example it might be 100 grams per litre of iron (that is 1.8 M) .
  • the cations are preferably at a concentration between 0.1 M and 5.0 M.
  • the beads were merely contacted with the calcium-containing solution, relying on imbibition of the solution into the pores of the proppant.
  • vacuum impregnation can again be used (as in step (ii) ) to promote contact between the solution and the solid scale inhibitor in the pores of the proppant .
  • the high initial dissolution rate observed above in graphs B and C is commonly observed with solid scale inhibitors, for example alkali metal (e.g. Na or K) or alkaline earth metal (e.g. Ca or Mg) salts of DTPMP, phosphino-carboxylic acid, polyvinyl sulphonate, polyacrylate, vinyl sulphonate and acrylic acid copolymer, aleic and acrylic acid copolymer, or other phosphonate-type inhibitors such as aminotrimethylene phosphonic acid.
  • the initial concentrations are typically in the range 1 000 - 100 000 ppm.
  • the high release rates are believed to be attributable to the heterogeneous composition of the solid scale inhibitor; compositions with relatively high alkali metal and low alkaline earth metal content dissolve preferentially when in contact with brine or water, whereas the dissolution of scale inhibitor compositions with relatively high alkaline earth metal content is slower.
  • cations such as calcium and/or magnesium at a concentration preferably in the range 5 000 to 150 000 ppm, and as the mole ratio of polyvalent cations to scale inhibitor is increased in the solution from which the inhibitor is deposited, the concentration of scale inhibitor in water subsequently flowing past the beads decreases.
  • the pH of the solution also affects the composition of the deposited scale inhibitor, and so affects the subsequent rate of dissolution of the inhibitor. Increasing the pH of the solution reduces the rate of release of the inhibitor subsequently, so the pH is generally adjusted to be in the range 6 to 11. Changing the composition of the deposited scale inhibitor in these ways affects the long- term release rates, but does not prevent the high initial release. Treating the deposited scale inhibitor with polyvalent cations as in step (iv) above does however effectively suppress this initial release.
  • the scale inhibitor initially deposited contains no alkaline earth metal ions.
  • the procedure is as follows:
  • the wet beads are then dried at 110°C, and if necessary loosened to be free-flowing, and sieved to remove any fines.
  • 100 g of " the dried beds contain about 2 g of DTPMP.
  • the volume of this solution is just enough to wet the surfaces of the beads; in this case it was about 16 ml to wet 100 g of the dried beads.
  • the wetted beads are then dried at 110°C, and if necessary are then loosened to be free-flowing and sieved to remove any fines.
  • the drying steps (iii) and (v) may be performed in a counter current rotary convective dryer, and this provides a free-flowing product.
  • the contacting step (iv) may be performed by exposing the dried beads to an atomised spray mist of the concentrated calcium salt solution.
  • the initially-deposited inhibitor might instead contain only one type of alkaline earth metal.
  • One such example is as follows:
  • the subsequent steps are as in Example 2.
  • the dried beads, of 9% porosity typically contain about 1.5 g of DTPMP per 100 g of beads.
  • PCA concentrated phosphino-carboxylic acid
  • the subsequent steps are as in Example 2.
  • the dried beads, of 9% porosity typically contain about 2 g PCA polymer per 100 g of beads.

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  • Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Physics & Mathematics (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Treatment Of Liquids With Adsorbents In General (AREA)
  • Solid-Sorbent Or Filter-Aiding Compositions (AREA)

Abstract

On prépare des particules contenant un anti-incrustant en mettant en contact des billes de céramique poreuses avec une solution d'anti-incrustant, puis en faisant sécher ces billes. Si les billes séchées sont alors mises en contact avec une solution contenant une concentration élevée de cations polyvalents, par exemple 2,5 M d'ions calcium, puis séchés une nouvelle fois, la vitesse de libération de l'anti-incrustant lorsque les billes sont ultérieurement mise en contact avec l'eau est réduite. En modifiant la concentration du cation polyvalent dans une intervalle de 1,0 à 5,0 M on modifie la vitesse à laquelle l'anti-incrustant est libéré par la suite. Ces billes peuvent être utilisées comme agents de soutènement de fracturation ou dans un filtre à gravier afin d'empêcher la formation d'incrustations dans un puits de pétrole ou de gaz.
PCT/GB1998/003863 1998-01-17 1998-12-21 Traitement de puits WO1999036668A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
AU17723/99A AU1772399A (en) 1998-01-17 1998-12-21 Well treatment

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB9800942.6 1998-01-17
GBGB9800942.6A GB9800942D0 (en) 1998-01-17 1998-01-17 Well treatment

Publications (1)

Publication Number Publication Date
WO1999036668A1 true WO1999036668A1 (fr) 1999-07-22

Family

ID=10825418

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/GB1998/003863 WO1999036668A1 (fr) 1998-01-17 1998-12-21 Traitement de puits

Country Status (3)

Country Link
AU (1) AU1772399A (fr)
GB (1) GB9800942D0 (fr)
WO (1) WO1999036668A1 (fr)

Cited By (19)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2007063325A1 (fr) * 2005-12-01 2007-06-07 Visible Technology Oil & Gas Limited Particules
US7419937B2 (en) 2002-12-19 2008-09-02 Schlumberger Technology Corporation Method for providing treatment chemicals in a subterranean well
GB2448442A (en) * 2004-12-15 2008-10-15 Bj Services Co Treatment agent adsorbed on a water-insoluble adsorbent
US20090038799A1 (en) * 2007-07-27 2009-02-12 Garcia-Lopez De Victoria Marieliz System, Method, and Apparatus for Combined Fracturing Treatment and Scale Inhibition
US7491682B2 (en) 2004-12-15 2009-02-17 Bj Services Company Method of inhibiting or controlling formation of inorganic scales
US7598209B2 (en) 2006-01-26 2009-10-06 Bj Services Company Porous composites containing hydrocarbon-soluble well treatment agents and methods for using the same
WO2012134506A1 (fr) * 2011-03-30 2012-10-04 Baker Hughes Incorporated Composites de traitement de puits à libération retardée pour une utilisation dans des fluides de traitement de puits
US20130157905A1 (en) * 2011-12-20 2013-06-20 Halliburton Energy Services, Inc. Method for the Removal or Suppression of Interfering Metal Ions Using Environmentally Friendly Competitive Binders
US20140262247A1 (en) * 2013-03-15 2014-09-18 Carbo Ceramics Inc. Composition and method for hydraulic fracturing and evaluation and diagnostics of hydraulic fractures using infused porous ceramic proppant
US9010430B2 (en) 2010-07-19 2015-04-21 Baker Hughes Incorporated Method of using shaped compressed pellets in treating a well
US9976070B2 (en) 2010-07-19 2018-05-22 Baker Hughes, A Ge Company, Llc Method of using shaped compressed pellets in well treatment operations
US10400159B2 (en) 2014-07-23 2019-09-03 Baker Hughes, A Ge Company, Llc Composite comprising well treatment agent and/or a tracer adhered onto a calcined substrate of a metal oxide coated core and a method of using the same
US10413966B2 (en) 2016-06-20 2019-09-17 Baker Hughes, A Ge Company, Llc Nanoparticles having magnetic core encapsulated by carbon shell and composites of the same
US10641083B2 (en) 2016-06-02 2020-05-05 Baker Hughes, A Ge Company, Llc Method of monitoring fluid flow from a reservoir using well treatment agents
US10822536B2 (en) 2010-07-19 2020-11-03 Baker Hughes, A Ge Company, Llc Method of using a screen containing a composite for release of well treatment agent into a well
US10961444B1 (en) 2019-11-01 2021-03-30 Baker Hughes Oilfield Operations Llc Method of using coated composites containing delayed release agent in a well treatment operation
US11254850B2 (en) 2017-11-03 2022-02-22 Baker Hughes Holdings Llc Treatment methods using aqueous fluids containing oil-soluble treatment agents
US11254861B2 (en) 2017-07-13 2022-02-22 Baker Hughes Holdings Llc Delivery system for oil-soluble well treatment agents and methods of using the same
US12060523B2 (en) 2017-07-13 2024-08-13 Baker Hughes Holdings Llc Method of introducing oil-soluble well treatment agent into a well or subterranean formation

Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2298440A (en) * 1995-02-28 1996-09-04 Atomic Energy Authority Uk Well treatment
WO1998040606A1 (fr) * 1997-03-13 1998-09-17 Aea Technology Plc Traitement d'un puits avec des particules

Patent Citations (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2298440A (en) * 1995-02-28 1996-09-04 Atomic Energy Authority Uk Well treatment
WO1998040606A1 (fr) * 1997-03-13 1998-09-17 Aea Technology Plc Traitement d'un puits avec des particules

Cited By (36)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7419937B2 (en) 2002-12-19 2008-09-02 Schlumberger Technology Corporation Method for providing treatment chemicals in a subterranean well
GB2448442A (en) * 2004-12-15 2008-10-15 Bj Services Co Treatment agent adsorbed on a water-insoluble adsorbent
US7491682B2 (en) 2004-12-15 2009-02-17 Bj Services Company Method of inhibiting or controlling formation of inorganic scales
GB2448442B (en) * 2004-12-15 2009-07-22 Bj Services Co Well treating compositions for slow release of treatment agents and methods of using the same
GB2421260B (en) * 2004-12-15 2009-07-22 Bj Services Co Well treating compositions for slow release of treatment agents and methods of using the same
US8735333B2 (en) 2005-12-01 2014-05-27 Ewen Robertson Particles
US20090143259A1 (en) * 2005-12-01 2009-06-04 Ewen Robertson Particles
EA013192B1 (ru) * 2005-12-01 2010-02-26 Визибл Текнолоджи Ойл Энд Гэс Лимитед Искусственная частица для применения в скважине либо в коллекторе
WO2007063325A1 (fr) * 2005-12-01 2007-06-07 Visible Technology Oil & Gas Limited Particules
US7598209B2 (en) 2006-01-26 2009-10-06 Bj Services Company Porous composites containing hydrocarbon-soluble well treatment agents and methods for using the same
US20090038799A1 (en) * 2007-07-27 2009-02-12 Garcia-Lopez De Victoria Marieliz System, Method, and Apparatus for Combined Fracturing Treatment and Scale Inhibition
US10822536B2 (en) 2010-07-19 2020-11-03 Baker Hughes, A Ge Company, Llc Method of using a screen containing a composite for release of well treatment agent into a well
US9010430B2 (en) 2010-07-19 2015-04-21 Baker Hughes Incorporated Method of using shaped compressed pellets in treating a well
US9976070B2 (en) 2010-07-19 2018-05-22 Baker Hughes, A Ge Company, Llc Method of using shaped compressed pellets in well treatment operations
CN103459548A (zh) * 2011-03-30 2013-12-18 贝克休斯公司 用于井处理流体的缓释井处理复合材料
US8664168B2 (en) 2011-03-30 2014-03-04 Baker Hughes Incorporated Method of using composites in the treatment of wells
WO2012134506A1 (fr) * 2011-03-30 2012-10-04 Baker Hughes Incorporated Composites de traitement de puits à libération retardée pour une utilisation dans des fluides de traitement de puits
AU2011363582B2 (en) * 2011-03-30 2016-04-28 Baker Hughes Incorporated Delayed release well treatment composites for use in well treatment fluids
CN103459548B (zh) * 2011-03-30 2017-05-24 贝克休斯公司 用于井处理流体的缓释井处理复合材料
US8993490B2 (en) * 2011-12-20 2015-03-31 Halliburton Energy Services, Inc. Method for the removal or suppression of interfering metal ions using environmentally friendly competitive binders
US20130157905A1 (en) * 2011-12-20 2013-06-20 Halliburton Energy Services, Inc. Method for the Removal or Suppression of Interfering Metal Ions Using Environmentally Friendly Competitive Binders
GB2511241B (en) * 2011-12-20 2017-12-27 Halliburton Energy Services Inc Method for the removal of interfering metal ions using environmentally friendly competitive binders
CN105189921A (zh) * 2013-03-15 2015-12-23 卡博陶粒有限公司 用于使用注入的多孔陶瓷支撑剂水力压裂及评估和诊断水力裂缝的组合物和方法
US10316242B2 (en) * 2013-03-15 2019-06-11 Carbo Ceramics Inc. Composition and method for hydraulic fracturing and evaluation and diagnostics of hydraulic fractures using infused porous ceramic proppant
US11286418B2 (en) 2013-03-15 2022-03-29 Carbo Ceramics Inc. Composition and method for hydraulic fracturing and evaluation and diagnostics of hydraulic fractures using infused porous ceramic proppant
US12037545B2 (en) 2013-03-15 2024-07-16 Carbo Ceramics Inc. Composition and method for hydraulic fracturing and evaluation and diagnostics of hydraulic fractures using infused porous ceramic proppant
US20220213378A1 (en) * 2013-03-15 2022-07-07 Carbo Ceramics Inc. Composition and method for hydraulic fracturing and evaluation and diagnostics of hydraulic fractures using infused porous ceramic proppant
US20140262247A1 (en) * 2013-03-15 2014-09-18 Carbo Ceramics Inc. Composition and method for hydraulic fracturing and evaluation and diagnostics of hydraulic fractures using infused porous ceramic proppant
CN105189921B (zh) * 2013-03-15 2021-03-02 卡博陶粒有限公司 用于使用注入的多孔陶瓷支撑剂水力压裂及评估和诊断水力裂缝的组合物和方法
US10400159B2 (en) 2014-07-23 2019-09-03 Baker Hughes, A Ge Company, Llc Composite comprising well treatment agent and/or a tracer adhered onto a calcined substrate of a metal oxide coated core and a method of using the same
US10641083B2 (en) 2016-06-02 2020-05-05 Baker Hughes, A Ge Company, Llc Method of monitoring fluid flow from a reservoir using well treatment agents
US10413966B2 (en) 2016-06-20 2019-09-17 Baker Hughes, A Ge Company, Llc Nanoparticles having magnetic core encapsulated by carbon shell and composites of the same
US11254861B2 (en) 2017-07-13 2022-02-22 Baker Hughes Holdings Llc Delivery system for oil-soluble well treatment agents and methods of using the same
US12060523B2 (en) 2017-07-13 2024-08-13 Baker Hughes Holdings Llc Method of introducing oil-soluble well treatment agent into a well or subterranean formation
US11254850B2 (en) 2017-11-03 2022-02-22 Baker Hughes Holdings Llc Treatment methods using aqueous fluids containing oil-soluble treatment agents
US10961444B1 (en) 2019-11-01 2021-03-30 Baker Hughes Oilfield Operations Llc Method of using coated composites containing delayed release agent in a well treatment operation

Also Published As

Publication number Publication date
AU1772399A (en) 1999-08-02
GB9800942D0 (en) 1998-03-11

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