WO2015126799A2 - Procédé permettant de former plusieurs fractures dans une formation - Google Patents

Procédé permettant de former plusieurs fractures dans une formation Download PDF

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Publication number
WO2015126799A2
WO2015126799A2 PCT/US2015/016088 US2015016088W WO2015126799A2 WO 2015126799 A2 WO2015126799 A2 WO 2015126799A2 US 2015016088 W US2015016088 W US 2015016088W WO 2015126799 A2 WO2015126799 A2 WO 2015126799A2
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WO
WIPO (PCT)
Prior art keywords
subterranean formation
fracture
fracturing fluid
microns
wellbore
Prior art date
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PCT/US2015/016088
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English (en)
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WO2015126799A3 (fr
Inventor
Shawn Patrick Holzhauser
Victoria Xiaoping Qiu
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Shell Oil Company
Shell Internationale Research Maatschappij B.V.
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.)
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Publication date
Application filed by Shell Oil Company, Shell Internationale Research Maatschappij B.V. filed Critical Shell Oil Company
Priority to CN201580009372.3A priority Critical patent/CN106030030A/zh
Priority to DE112015000858.6T priority patent/DE112015000858T5/de
Priority to RU2016137201A priority patent/RU2016137201A/ru
Priority to AU2015219231A priority patent/AU2015219231A1/en
Priority to CA2938890A priority patent/CA2938890A1/fr
Priority to GB1613469.4A priority patent/GB2538431A/en
Publication of WO2015126799A2 publication Critical patent/WO2015126799A2/fr
Publication of WO2015126799A3 publication Critical patent/WO2015126799A3/fr

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Classifications

    • 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
    • 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
    • C09K8/516—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls characterised by their form or by the form of their components, e.g. encapsulated material
    • 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
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/70—Compositions for forming crevices or fractures characterised by their form or by the form of their components, e.g. foams
    • 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
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/72—Eroding chemicals, e.g. acids
    • C09K8/74—Eroding chemicals, e.g. acids combined with additives added for specific purposes
    • 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
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • 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
    • 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

  • Proppant material such as sand, ceramic beads, or other material may be injected in a later portion of the fracturing fluid to hold the fracture open after pressure on the fracturing fluid is decreased.
  • Either cased or uncased wellbores may be fractured, but typically wellbores within target formations are cased, the casings cemented, and then the cemented casings are perforated at predetermined intervals along the length of the wellbore.
  • the fracturing fluids may contain acids or acid precursors that react with carbonates to alter the shape of the rock at the surface of the fracture so that after pressure on the fracturing fluid is released, and the fracture closes, the faces of the rock no longer match.
  • Flow paths for fluids to traverse from along the surface of the fracture to the wellbore are therefore provided.
  • US patent 7,644,761s uggests a method where slugs of proppant are injected in an acid fracturing fluid so that existing fractures may be plugged, permitting pressure within the wellbore to increase to above a fracture initiation pressure and thereby initiation of a second or subsequent fracture.
  • the proppant may be a combination suggested in US patent
  • the method includes using fibers to aid in transporting, suspending and placing proppant or gravel in viscous carrier fluids otherwise having insufficient viscosity to prevent particulate settling. Fibers are suggested that have properties optimized for proppant transport but degrade after the treatment into degradation products that do not precipitate in the presence of ions in the water such as calcium and magnesium.
  • a system and technique are provided to provide propped hydraulic fractures in a subterranean formation comprising: injecting a fracturing fluid into the subterranean formation at a pressure sufficient to initiate and propagate at least one hydraulic fracture wherein the fracturing fluid comprises a proppant; when the at least one hydraulic fracture has reached a target size, adding to the fracturing fluid a predetermined amount of a diverter material wherein the diverter material comprises between 10 to 30 weight percent of particles having a size larger than 2000 microns, between 1 and 15% by weight of particles between 1000 and 2000 microns, 10 to 40 percent by weight particles having a diameter in the range of 500 to 1000 microns, 40 to 70 percent by weight particles smaller than 500 microns, and comprising a material that degrades at conditions of the subterranean formation, the diverter material effective to essentially block flow of fracturing fluid into the at least one fracture; and continuing to inject fracturing fluid at a pressure effective to initiate at
  • the diverter material may be, for example polylactate, polyglycolate, or oil soluble resins. Slugs of diverter material may be injected may be injected between batches of injected fracturing fluid with each batch of diverter inhibiting flow of fracturing fluid into existing fractures. The greater the flow of fracturing fluid going into a particular fracture, the greater the amount of diverter initially entering the fracture will be, and thus rapidly growing fractures will be limited to essentially the size of the fracture at the time the diverter is injected. This allows subsequent fractures to become larger instead of dominate fractures containing the majority of the fracturing fluid and proppant.
  • the size range of the diverter material is selected to enable bridging at the perforations and therefore blockage of fluid flow at the perforation.
  • the amount of diverter needed is predictable, and the amount of diverter is also considerably less than if the divertor were to be sized to block fluid flow in the fracture or within the proppant that has been placed within the fracture.
  • Minimizing the amount of diverter material needed reduces costs of the diverter material, the costs and equipment needed to add the diverter material, and minimizes damage caused by the residual of the diverter material left in the formation after degradation of the diverter material.
  • Figure l is a schematic drawing of a wellbore fractured according to the process of the present invention.
  • Figures 2 and 3 are plots of the amount of fracturing fluid forced into perforations in segments of wellbores with and without the use of the present invention.
  • a wellbore 101 penetrating a subterranean formation 102.
  • the subterranean formation could be, for example, a hydrocarbon containing formation such as a light tight oil reservoir or a tight gas reservoir, or a formation into which carbon dioxide is to be sequestered.
  • a hydrocarbon containing formation such as a light tight oil reservoir or a tight gas reservoir
  • a formation into which carbon dioxide is to be sequestered Generally formations having limited permeability require hydraulic fracturing such as provided by the present invention in order for fluids to be produced or injected into the formations.
  • Low permeability formations could be formations having less than 10 milidarcy permeability.
  • the wellbore could be vertical, horizontal, or deviated.
  • long horizontal wellbores are typically used for light tight oil and tight gas production so that many hydraulic fractures could be provided from each wellbore.
  • the wellbore is provided by known drilling and completion methods.
  • the wellbore could be an open hole completion within the formation to be produced, but to provide multiple fractures without having to move packers, wellbores that are cased with casing 103 and cemented into the formation with cement 104.
  • the cement is generally pumped down the casing and followed by a wiper 105, which separates the cement from wellbore fluids behind the cement.
  • the wiper may be stopped by a stopper ring 106 at the end of the casing.
  • Known cement compositions and methods could be applied with the present invention.
  • a previously fractured segment of the wellbore 107 is show with three fractures 108 already provided into the subterranean formation.
  • the casing is shown as having been provided with perforations 109 which penetrate the casing into the subterranean formation.
  • the tubular 112 is shown attached to both packers, and packers could be provided that could be released and moved via a separate hydraulic control line (not shown), or set to provide an isolated segment of the wellbore between the two packers.
  • a horizontal wellbore having a horizontal section 1828.8 meters long could be provided with hydraulic fractures every 15 to 200 meters to provide a wellbore having from 10 to 120 fractures.
  • the fractures could be provided in sets of, for example, 2 to 10 fractures at a time. By providing multiple fractures at one time it is meant that the fractures are provided without changing the zone within the wellbore into which fracturing fluid is injected.
  • fracturing fluid 113 could be injected into the isolated segment of the wellbore 114, and through perforations 109, into the subterranean formation 102 at a pressure sufficiently high to initiate at least one new fracture.
  • Fracturing fluids 113 may be thickened to lower the rate at which proppants settle from the fluids, enabling the fluids to carry the proppants deeper into fractures.
  • Thickeners may be viscosifying polymers such as a solvatable (or hydratable) polysaccharide, such as a galactomannan gum, a glycomannan gum, or a cellulose derivative. Examples of such polymers include guar, hydroxypropyl guar, carboxymethyl guar, carboxymethylhydroxyethyl guar, hydroxyethyl cellulose, carboxymethyl-hydroxyethyl cellulose, hydroxypropyl cellulose, xanthan, polyacrylamides and other synthetic polymers. Of these, guar,
  • a fracturing fluid can be what is known as a slick water composition.
  • a slick water comprises water and a low concentration of friction reducer along with a proppant such as sand.
  • slick water coBtains 99.5 percent by weight of water a d sand, and 0.5 pereeont by weight of additives, including, tor example; a friction reducing polymer such as polyacrylami.de; biocides such as bromine, methanol or naphthalene; surfactants such as butanol, or ethylene glycol monobutyi ether: and scale inhibitors such as hyclrochiorine acid or ethylene glycol.
  • the slick water fracturing fluid does not include thickeners. High pumping rates are used to place the fracturing fl ids within the formations before the proppants settle from the fluids.
  • Slick water compositions axe therefore more useful in shallow wells, wells with shorter horizontal laterals, or near the heal end of long horizontal wells.
  • slick water compositions are generally preferred because thickeners increase hydraulic factional pressure losses, and cause at least some forma ion damage,
  • Hydraulic fractures may be initiated with fluids not containing proppants, but proppants can then be added as the fractures propagate.
  • Proppants may be sands or ceramic particles, polymer pellets, or glass particles.
  • Proppants provide a more permeable filler for hydraulic fractures if they are provided with a relatively narrow range of sizes.
  • Proppants such as those disclosed in US patent nos. 7,913,762, 7,836,952, or 8,327,940 could be used in the present invention.
  • Proppants having relatively narrow size distributions provide high permeability propped fractures because void volumes are maximized. Typical volume average size of useful proppants range from 100 to 2000 microns, and the distributions are preferably narrow.
  • Fracturing proppants size is specified as a mesh screen size that the sand pass through and a second mesh screen size which the proppant does not pass through.
  • Porppant sizes useful in the present invention include, for example, 8/12, 10/20, 20/40, and 70/140. These screens correspond, respectively, to size range of 1.68 to 2.38, 0.84 to 2.00, 0.42 to 0.84, millimetres, and 105 to 210 microns. Most often, 20/40 sand is utilized.
  • Fracturing sand is also specified by sphericity and roundness by a chart devised by Krumbein and Sloss, and typically both sphericity and roundness are greater than 0.6 according to the chart of Krumbein and Sloss.
  • proppant injection is discontinued after a pre-determined amount of proppant has been injected to prevent proppant from filling the wellbore.
  • the pre-determined amount of proppant could be estimated as the amount of proppant that could be placed in a fracture without the proppant "sanding out", or becoming bridged within the facture and blocking further movement of proppant into the fracture.
  • a flush of fracturing fluid that does not contain proppant will be injected to move proppant from within the wellbore into the fractures.
  • a slug of a diverter material is pumped into the wellbore, preferably after the flush of proppant free fracturing fluid.
  • the slug of diverter material comprises water or fracturing fluid, and diverter materials.
  • the amount of pre-determined amount of proppant and fluid is based on fracturing job design that would give the target size of fractures.
  • the size of the area of the fracture may be inferred from micro seismic data, or it could be inferred merely from the volume of proppant containing fracturing fluid, or proppant, that has been injected.
  • the amount of fracturing fluid may be determined for the set of perforations to be fractured to optimize the fracturing based on normal considerations including the cost of the factures and the value of marginally larger fractures, and then this amount of fracturing fluid being injected in essentially equal portions, separated by slugs of fracturing fluid containing diverter material.
  • the fracturing fluid may be divided into, for example, two, three, or four essentially equal portions, separated by one, two or three slugs of diverter materials.
  • Portions of fracturing fluids and proppants separated by the diversion slugs may be unequal based on fracturing design optimizations.
  • the pressure at which fracturing fluid is being injected is typically stable. After the fluid containing the diverter has been injected, and the diverter material has traversed the tubular to the zone being fractured, the pressure at the wellhead will be seen to rise as fluid flow to existing fractures is blocked by the diverter material. Eventually, additional fractures open. Increases in pressure from fifty to three thousand pounds per square inch have been observed after injection of a slug of diverter. Because initial fractures increase the stress on the formation, each successive fracture will require increased pressure to initiate and propagate. Acceptable diverter material may be, for example, polylactate, polyglycolate, or oil soluble resins.
  • Manufactures of such materials are capable of providing particles of such materials having specified size ranges and distributions, and which degrade under formation conditions at predictable rates.
  • Diverters of the present invention degrade at formation conditions over a time period that permits production of hydrocarbons from the wellbore within a reasonable amount of time.
  • the diverters may be designed to degrade at formation conditions between six and ninety days.
  • degrade it is meant that the polymers lose more than half of their tensile strength.
  • the degradation could also be accomplished by providing diverter material which is at least partially soluble in formation fluids, such as oil.
  • the degradation could also be accomplished, accelerated, or triggered, by, for example, flushing an acidic component into the perforations.
  • a diverter material could be used that reacts with oxidizing agents and the degradation could be accomplished, accelerated, or triggered by flushing the perforations with an oxidizing agent.
  • the maximum size of the diverter, and the amount expected to block each perforation may be determined by, for example, labatory tests flowing diverter material through perforated rocks.
  • Diverter material could be added to the fracturing fluid as it is being injected, for example, by a screw pump into a mixing vessel or by direct manual feeding into a mixing vessel, and then being feed to fracturing fluid injection pumps.
  • the diverter material may be added in a concentration that is great enough to be effective. If the concentration is not sufficient, the diverter material will not be sufficient to block flow into the fracture. To high of a concentration of diverter will be uneconomical, and difficult to add and mix into the fracturing fluid. Concentrations of diverter material between about 25 and about 200 grams per liter of fracturing fluid have been found to be effective and cost effective. Concentrations of between about 50 and 100 grams per liter may be acceptable.
  • the size distribution of the diverter material must be sufficiently broad.
  • An acceptable broad particle size range would be a combination of particles wherein between 10 to 30 weight percent of particles have a size larger than 2000 microns, between 1 and 15% by weight of particles between 1000 and 2000 microns, 10 to 40 percent by weight particles having a diameter in the range of 500 to 1000 microns, 40 to 70 percent by weight particles smaller than 500 microns.
  • the largest particles need to be large enough to bridge the perforations at the opening, and there need to be a sufficient amount of particles about one third of that size to bridge the openings between the largest particles, and then a sufficient amount of particles small enough to bridge the openings of between the smaller particles, and so on, until the particle size is below 500 micron.
  • the different size range particles could be injected at one time, or could be injected sequentially with larger sizes injected first.
  • the size of the largest diverter particles depends upon where the diverter material is intended to block flow into the formation. If it is intended that flow into the formation is to be blocked at the face of proppant within the fracture, then this maximum diameter of diverter may be about one half of the average diameter of the proppant. If the diverter is intended to block flow within the fracture, then this maximum diameter of the diverter may be about one half of the width of the expected fracture opening. If the flow is intended to be blocked at the perforation itself, then the maximum diameter of the diverter material should be about half of the diameter of the perforation.
  • the size distribution of the diverter material is preferably selected to block perforations. Blocking of the perforations can be accomplished with, for example, three to thirty kilograms of properly sized materials for each perforation. The amount of diverter material needed to block the perforations is also much more predictable than the amount of material needed to block the fracture or the proppant placed within the fracture because the dimensions of the actual perforation are known and are not significantly altered by the fracturing process.
  • the amount of diverter material may be, for example, between one and thirty kilograms per perforation to be blocked.
  • the present invention may be utilized to provide multiple fractures from within an isolated section of a wellbore, or could be utilized to provide fractures from a wellbore without isolating a section.
  • the whole segment of the wellbore to be provided with factures could be subjected to sequences of proppant containing fracturing fluids followed by slugs of diverter material repeatedly until fractures have been provided from each of the perforations in the wellbore without isolating sections of the wellbore.
  • the present invention could also be used with a well from which fractures had previously been provided.
  • proppant could be forced into existing fractures prior to could be subjected to injection of diverter material, to reopen or enlarge existing fractures.
  • flow into existing fractures could be inhibited by injection of diverter material before new fractures are placed from the wellbore.
  • hydrocarbons may be produced from the formation by way of the hydraulic fractures.
  • the hydrocarbons may be, for example, natural gas, crude oil, and/or light tight oil.
  • the total amount of proppant pumped was about 900,000 pounds.
  • the proppant and fluid was injected in three roughly equal batches, each batch separated by a slug of diverter material in fluid.
  • For each batch of diverter about 450 pounds of diverter material was added to 600 gallons of liner gel solution.
  • the diverter caused the back pressure to build by about 700 psi.
  • a second batch of proppant was pumped.
  • the second batch of proppant required about two hundred psi more pressure than the first. This indicates that new perforations were opening.
  • the second batch of diverter material was pumped.
  • the diverter material was commercially available material, Biovert, from Halliburton Energy Services, Inc., of Houston, Texas.
  • the well was a well equipped with a fiber optic sensor capable of measuring a complete temperature and acoustic profile within the well. With the complete acoustic and temperature profile, as a function of time, the distribution of fracturing fluid going into different perforations within a cluster may be calculated.
  • a cluster of six perforations are fractured, there will be one to three dominate fractures, with three to five fractures receiving considerably less proppant. Therefore, normal procedures would be to not attempt to fracture more than three clusters per stage.
  • Figure 1 shows the relative distribution of proppant material for the two batches of proppant for each of six clusters of perforations.
  • the proppant pumped first went mostly into the first three sets of perforations. It can be seen that over ninety percent of the proppant went into these perforations.
  • Much more of the second batch of proppant went into the other three perforations, with about fifty percent going into the fourth perforation and less than ten percent going into each of the first three.
  • sufficient proppant was not forced into the fifth and sixth perforations, the distribution of proppant was significantly improved by the slug of diverter material.
  • FIG. 1 Another test to determine if open clusters could be blocked to divert fracture fluids into unopened clusters of perforations in a horizontal well in the Eagle Ford formation.
  • the diverter used was commercially available Bio Vert from Halliburton.
  • the x-axis is the number for clusters in one stage.
  • the Y axis is the percentage of fracturing fluid and slurry taken by each clusters. During the job, the total fluid and slurry volume were divided into two portions. The first portion was pumped as a regular fracturing procedure. The solid line indicates the percentage of fluid and slurry taken by each cluster during the first portion of the treatment calculated from fiber optic temperature sensor data.

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Abstract

La présente invention concerne un système et une technique permettant de former des fractures hydrauliques soutenues dans une formation souterraine, la technique comprenant : l'injection d'un fluide de fracturation dans la formation souterraine à une pression suffisante pour initier et propager au moins une fracture hydraulique, le fluide de fracturation contenant un agent de soutènement ; quand la ou les fractures hydrauliques ont atteint une taille cible, l'ajout au fluide de fracturation d'une quantité prédéterminée d'un matériau de dérivation, le matériau de déviation comprenant essentiellement 10 à 30 pour cent en poids de particules ayant une taille supérieure à 2 000 microns, 1 % et 15 % en poids de particules entre 1 000 et 2 000 microns, 10 à 40 pour cent en poids de particules ayant un diamètre de 500 à 1 000 microns, 40 à 70 pour cent en poids de particules plus petites que 500 microns, et comprenant un matériau qui se dégrade dans les conditions de la formation souterraine, le matériau de déviation étant efficace pour bloquer l'écoulement du fluide de fracturation dans la ou les fractures ; et la poursuite de l'injection du fluide de fracturation à une pression efficace pour initier au moins une fracture supplémentaire à l'intérieur de la formation souterraine.
PCT/US2015/016088 2014-02-19 2015-02-17 Procédé permettant de former plusieurs fractures dans une formation WO2015126799A2 (fr)

Priority Applications (6)

Application Number Priority Date Filing Date Title
CN201580009372.3A CN106030030A (zh) 2014-02-19 2015-02-17 在地层中提供多个裂缝的方法
DE112015000858.6T DE112015000858T5 (de) 2014-02-19 2015-02-17 Verfahren zum Bereitstellen von mehreren Rissen in einer Formation
RU2016137201A RU2016137201A (ru) 2014-02-19 2015-02-17 Способ формирования множественных трещин в пласте месторождения
AU2015219231A AU2015219231A1 (en) 2014-02-19 2015-02-17 Method for providing multiple fractures in a formation
CA2938890A CA2938890A1 (fr) 2014-02-19 2015-02-17 Procede permettant de former plusieurs fractures dans une formation
GB1613469.4A GB2538431A (en) 2014-02-19 2015-02-17 Method for providing multiple fractures in a formation

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US201461941583P 2014-02-19 2014-02-19
US61/941,583 2014-02-19

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WO2015126799A2 true WO2015126799A2 (fr) 2015-08-27
WO2015126799A3 WO2015126799A3 (fr) 2016-01-28

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US (1) US20150233226A1 (fr)
CN (1) CN106030030A (fr)
AR (1) AR099425A1 (fr)
AU (1) AU2015219231A1 (fr)
CA (1) CA2938890A1 (fr)
DE (1) DE112015000858T5 (fr)
GB (1) GB2538431A (fr)
RU (1) RU2016137201A (fr)
WO (1) WO2015126799A2 (fr)

Cited By (3)

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CN105086973A (zh) * 2015-09-02 2015-11-25 中国石油集团渤海钻探工程有限公司 修井液用自分解暂堵剂及其使用方法
US11047220B2 (en) 2017-01-31 2021-06-29 Halliburton Energy Services, Inc. Real-time optimization of stimulation treatments for multistage fracture stimulation
CN113528102A (zh) * 2020-04-17 2021-10-22 中石化石油工程技术服务有限公司 一种可完全降解的钻井液用封堵剂及其制备方法

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US10041327B2 (en) 2012-06-26 2018-08-07 Baker Hughes, A Ge Company, Llc Diverting systems for use in low temperature well treatment operations
US9920610B2 (en) * 2012-06-26 2018-03-20 Baker Hughes, A Ge Company, Llc Method of using diverter and proppant mixture
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US20150233226A1 (en) 2015-08-20
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DE112015000858T5 (de) 2016-11-03
CA2938890A1 (fr) 2015-08-27
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