WO2011145966A1 - Procédé de fracturation hydraulique - Google Patents

Procédé de fracturation hydraulique Download PDF

Info

Publication number
WO2011145966A1
WO2011145966A1 PCT/RU2010/000248 RU2010000248W WO2011145966A1 WO 2011145966 A1 WO2011145966 A1 WO 2011145966A1 RU 2010000248 W RU2010000248 W RU 2010000248W WO 2011145966 A1 WO2011145966 A1 WO 2011145966A1
Authority
WO
WIPO (PCT)
Prior art keywords
fluid
proppant
viscosity
injected
mpa
Prior art date
Application number
PCT/RU2010/000248
Other languages
English (en)
Inventor
Evgeny Borisovich Barmatov
Sergey Mikhailovich Makarychev-Mikhailov
Dmitry Ivanovich Potapenko
Christopher N. Fredd
Original Assignee
Schlumberger Canada Limited
Service Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
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 Schlumberger Canada Limited, Service Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited filed Critical Schlumberger Canada Limited
Priority to US13/698,658 priority Critical patent/US20130105157A1/en
Priority to PCT/RU2010/000248 priority patent/WO2011145966A1/fr
Priority to CA2799555A priority patent/CA2799555A1/fr
Priority to CN2010800681277A priority patent/CN103109039A/zh
Priority to MX2012013299A priority patent/MX341853B/es
Priority to RU2012154650/03A priority patent/RU2523316C1/ru
Priority to ARP110101681A priority patent/AR081195A1/es
Publication of WO2011145966A1 publication Critical patent/WO2011145966A1/fr

Links

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
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/66—Compositions based on water or polar solvents
    • C09K8/68—Compositions based on water or polar solvents containing organic compounds
    • C09K8/685—Compositions based on water or polar solvents containing organic compounds containing cross-linking agents
    • 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

Definitions

  • low-viscosity fluids for fracture stimulation in low- permeability reservoirs sometimes results in the creation of a network of intersecting fractures and sometimes results in propagation of a single fracture plane.
  • the low conductivity achieved with these treatments is often adequate in shale formations, it is believed that an increase in the contact area by generation of a complex fracture network is one of the key factors that can enhance hydrocarbon production in such formations.
  • One embodiment of the invention is a method for fracturing a subterranean formation in which a sequence of fluids is injected into the formation; the sequence has as a feature a first cycle that involves (a) injecting a pad fluid having a viscosity of less than about 50 mPa-s at a shear rate of 100 s ⁇ 1 under ambient conditions, (b) injecting proppant slurry having a viscosity of less than about 50 mPa s at a shear rate of 100 s "1 under ambient conditions, (c) injecting a thickened fluid (that will act as a diverting agent) having a viscosity of greater than about 50 mPa-s at a shear rate of 100 s "1 under ambient conditions, and one or more than one subsequent cycles incorporating repeating steps (b) and (c).
  • a pad fluid is injected first.
  • the permeability of the formation is less than about 1 mD.
  • the thickened diverting fluid has a viscosity of less than about 20 mPa-s as pumped and then thickens in the reservoir, for example the reservoir contains carbonate and the thickened fluid is initially acidic and becomes more viscous as acid is consumed.
  • Self-diverting acids systems may be used to form such systems that thicken in the reservoir.
  • the thickened fluid further contains a proppant;
  • the total volume of the fluid injected in steps (b) is at least 75 percent of the total volume of fluid injected in the treatment; and the fluid injected in steps (b) carries at least 90 percent of the total proppant injected in the treatment;
  • the proppant has a shape selected for example from spheres, rods, cylinders, plates, sheets, spherocylinders, ellipsoids, toruses, oblongs, fibers, arches/cells, meshes, meshes/cells, honeycombs, bubbles, sponge-like or foam structures, and mixtures of these shapes; the size of the proppant ranges from about 5 to about 1000 microns.
  • At least one of the injected fluids comprises solid degradable materials, for example polylactic acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and mixtures of these materials.
  • the degradable materials are typically used in the form of fibers, plates, flakes, beads and combinations thereof.
  • the fluid of step (a) or the fluid of step (b) or both contain a friction reducing agent.
  • the fluid of step or steps (c) may optionally contain less than about 0.024 kg proppant per liter of clean fluid or may optionally be substantially proppant free.
  • one or more than one cycle is followed by injection of a fluid having a viscosity of greater than about 50 mPa-s at a shear rate of 100 s "1 under ambient conditions and containing a coarse proppant; the one or more steps of injection of a fluid having a viscosity of greater than about 50 mPa-s at a shear rate of 100 s "1 under ambient conditions containing a coarse proppant may optionally be followed by injection of a fluid containing a proppant flowback control agent.
  • the method includes a final step of injecting a flush fluid; at least one of the fluids is viscosified with a degradable viscosifying agent.
  • the total volume of the fluid injected in steps (c) preferably makes up less than 10 percent of the total volume of fluid injected in the treatment.
  • the ratio of the volume of fluid in stage C to the volume of fluid in stage B is preferably less than about 1/10.
  • Figure 1 illustrates fracture system complexity, increasing from A to B to C.
  • Figure 2 is a schematic of the manifold system.
  • Figure 3 shows the pressure in the manifold system vs. time.
  • the invention will be described in terms of the treatment of vertical wells, but is equally applicable to wells of any orientation.
  • the invention will be described for hydrocarbon production wells, but it is to be understood that the invention may be used for wells for production of other fluids, such as water or carbon dioxide, or, for example, for injection or storage wells.
  • concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated.
  • each numerical value should be read once as modified by the term "about” (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context.
  • a range of from 1 to 10 is to be read as indicating each and every possible number along the continuum between about 1 and about 10.
  • a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to within the range, it is to be understood that the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range.
  • a sequence of stages is pumped into the reservoir; a low viscosity fluid treatment is complemented by at least one stage of pumping of a relatively low volume of a fluid, viscosified by a degradable viscosifying agent that is used as a diverting agent.
  • Pumping of the viscous fluid diverting agent leads to a net pressure increase and to plugging of some of the microfractures in the initial fracture system created, which induces formation of supplementary microfractures connected to the initial fracture network and increases the contact area with the formation rock.
  • the injection of viscous slugs of diverting agent is generally repeated.
  • Such a use of slugs of a viscous fluid enables stimulation of larger reservoir volumes in remote regions of a reservoir. After the treatment, the viscosified fluid degrades naturally or is destroyed with a breaker, opening up production from the temporarily-plugged fractures.
  • the present invention relates to a method of treatment redirection within an already stimulated zone which results in creation of a larger contact area with the reservoir because of a fracture complexity increase within that zone. When multiple productive zones are fracture stimulated it is often necessary to treat multiple zones in multiple stages. This creates a need for a diverting technique which enables treatment redirection from zone to zone.
  • Such diversion is done, for example, with bridge plugs, ball sealers, solid gel plugs, or plugs of degradable fibers, powder, flakes, granules, pellets, and chunks, optionally with slowly water-soluble coatings.
  • the other situation in which diversion is required is treatment redirection within a stimulating zone. In this case an additional formation rock volume is stimulated using the same entry point in the formation without treatment redirection to another zone along the wellbore.
  • techniques have been developed using slugs of viscous fluids or fine sand for control of leak-off and for fracture complexity decrease, not increase, in naturally fractured reservoirs. Creation of a single fracture plane in the near- wellbore zone instead of multiple interconnected fracture channels has in the past been sought deliberately to provide a significant tortuosity decrease and minimize the risk of premature screen-out.
  • Slickwater treatments have been shown to provide production comparable to that from conventional gel treatments, but for significantly lower cost.
  • One of the most important features of slickwater jobs is low gel damage, due to the low polymer content of the fluid.
  • the low fluid viscosity strongly affects its proppant transport properties, and placement of proppant deep into a fracture is a challenge.
  • Utilization of lightweight and ultra lightweight proppants has been one solution.
  • Another solution is pumping a combination of slickwater and gel in stages with varying quantities of proppants; such treatments are often referred as hybrid fracs or hybrid water fracs.
  • hybrid fracs Although the objective of hybrid fracs is better proppant placement with a fluid of higher viscosity than that of slickwater, other benefits have been noted including creation of wider fractures and thus avoidance of proppant bridging. It has also been noted that hybrid fracs can generate longer effective frac lengths, but the effective conductivities in the hybrid fracs were not consistently higher than those in water fracs. Slickwater fracs with no proppant or with coarse proppant only, or with alternation of these two, have been tried.
  • the usual slickwater treatment includes the following stages: a) slickwater pad; b) slickwater stage with fine proppant (for example approximately 100-mesh sand (grains of from about 0.105 to about 0.21 mm) or about 30/70 sand (about 0.21 to about 0.595 mm)) in concentrations gradually increasing from about 0.1 to about 2 ppa (pounds proppant added) (about 0.012 to about 0.240 kg of sand added per liter of clean fluid); c) linear gel (with a typical viscosity of from about 10 to about 100 mPa s at a shear rate of 100 s ⁇ 1 ) with coarse proppant (for example approximately 20/40 sand (about 0.42 to about 0.841 mm) or about 20/40 resin coated sand) in concentrations increasing to up to about 5 ppa (about 0.6 kg of sand added per liter of clean fluid) to prop open the near wellbore region of the fracture; and d)
  • the pad stage is from about 500 to about 3000 bbl (about 80 to about 480 m 3 )
  • the slickwater stage is from about 500 to about 25,000 bbl (about 80 to about 4000 m 3 )
  • the gel stage is from about 500 to about 25,000 bbl (about 80 to about 4000 m 3 ) and the flush is approximately the volume of the wellbore from the wellhead to the perforations, sometimes plus up to about 50 bbl (about 8 m 3 ).
  • hybrid treatments attempt to achieve the benefits of both conventional gel and slickwater treatments.
  • hybrid fracs include pumping of: a) slickwater pad; b) an optional slickwater stage with fine proppant (for example less than about 0.5 ppa (about 0.06 kg/I of clean fluid)); c) cross- linked gel with a viscosity of about 100 to about 1000 mPa-s at a shear rate of 100 s _1 with coarse proppant, for example about 20/40 (about 0.4 to about 0.841 mm), (at a concentration for example of up to about 5 ppa (about 0.6 kg of sand added per liter of clean fluid)); optionally repeating stages b) and c); and flush.
  • volumes are typically about the same as for the conventional slickwater treatments described above.
  • a reverse hybrid frac the sequence of fluid injection is changed, so a high viscosity polymer (linear or cross-linked) is used to create a fracture, while the proppant, transported with a low viscosity fluid, is pumped behind the viscous pad.
  • the viscosity contrast results in the formation of fingers of low viscosity proppant laden fluid in the higher viscosity fluid and proppant settling is hindered by the layers (fingers) of the more viscous fluid.
  • the objective of the design is to deliver proppant deeper into the fracture to ensure longer propped length and higher fracture conductivity.
  • any slickwater pumping schedule when the fluid is switched from slickwater to viscous proppant slurry, the fluid may be changed from slickwater to viscous fluid for a period before proppant is added; for example in another version of a hybrid frac, slickwater is pumped first to generate length; this is then followed by a crosslinked gel pad, and then by coarse sand in a crosslinked gel.
  • Unconventional gas reservoirs are characterized by extremely low formation permeabilities (for example less than about 0.1 mD down to about 100 nD in shales), and stimulation treatments often require large treatment volumes (for example over about 15,000 m 3 (1 Mgal)) and high pumping rates (as examples, at least about 6.4 m 3 /min (40 bpm), typically about 10 m 3 /min (60 bpm), and sometimes up to about 20 m 3 /min (120 bpm)) to open long fractures and generate complex fracture networks, which can provide unrestricted gas flow towards a wellbore.
  • high pumping rates as examples, at least about 6.4 m 3 /min (40 bpm), typically about 10 m 3 /min (60 bpm), and sometimes up to about 20 m 3 /min (120 bpm)
  • the fractures typically are propped with sands of various sizes transported by slickwater fluids, which are usually water with small amounts of polymeric friction reducers, having viscosities up to about 50 mPa-s at a shear rate of 100 s "1 . Fluids having higher viscosities, for example above about 15 cP would typically be called water frac fluids.
  • Lightweight proppants for example having specific gravities of from about 2.2 to about 2.8, and ultra lightweight proppants for example having specific gravities of from about 1.0 to about 2.0 may be used for water fracs.
  • Slickwater fluids contain significantly lower polymer concentrations than linear or cross-linked gels, so they do much less damage to the proppant pack.
  • ESV effective stimulated volume
  • the methods rely on temporary plugging of some zones (for example already-stimulated zones) in order to stimulate others with the same treatment.
  • Most of the existing diversion methods target wellbores and perforations to stimulate different formation zones.
  • These methods include various casing-conveyed zonal isolation tools, such as bridge plugs, sand plugs, ball sealers, induced stress diversion and others. Diversion within a fracture is less common in the art of hydraulic fracturing.
  • One method provides near-wellbore fracture diversion on demand. The method uses a mixture of proppant and degradable fiber and a placement strategy to plug a fracture face temporarily in the near wellbore region to enable treatment diversion to a different wellbore zone.
  • the present invention discloses a method of fracture network complexity increase and reservoir contact area enhancement by means of viscosified fluids.
  • the viscosified fluids may be selected from fluids such as, but not limited to, viscoelastic surfactants, borate and/or metal cross-linked polysaccharides, for example guar gums, cellulose derivatives, xanthans, scleroglucans, etc.
  • the fluids may further include crosslink delay agents to control the fluid viscosity, breakers, including encapsulated breakers, to ensure slug degradation after the treatment, degradable fibers and other additives.
  • Such fluids and their components are known to those skilled in the art.
  • the method is preferably applied to formations having a permeability less than about 1 mD, and more preferably to formations having a permeability less than about 10 mD, and most preferably to shale formations with permeabilities less than 1000 nD.
  • the method may be used in a refracturing treatment.
  • a typical treatment of the invention starts with a pad, stage A, in which a pure slickwater fluid is pumped.
  • the pad stage creates the fracture system and ensures that the width is sufficient for proppant passage.
  • the pad stage is followed by a large-volume stage B, pumping of a proppant-laden slickwater, which delivers the proppant into the opened main fracture and additional fracture networks.
  • Fluid B makes up at least 75 percent of the total fluid volume of the treatment.
  • the fluids of stages A and B have viscosities of less than about 50 mPa-s at a shear rate of 100 s ⁇ under ambient conditions, preferably from about 1 to about 10 mPa-s at a shear rate of 00 s "1 .
  • Fluids A and B may be the same or different.
  • the proppants for slickwater treatments are known to those skilled in the art; non-limiting examples include sands and other rocks and minerals, including muscovite mica, ceramics, polymeric materials, biomaterials and mixtures of these materials. Special attention should be paid to the choice of proppant material, as slickwaters have quite poor transport properties due to their very low viscosities.
  • a diversion stage C follows the far-field placement of proppant in stage B and involves pumping of a viscosified fluid, which may optionally further contain proppant and/or fiber material(s).
  • the fluid of stage C has a viscosity, after viscosifying, greater than about 50 mPa-s, preferably from about 100 to about 1000 mPa-s, at a shear rate of 100 s ⁇ 1 under ambient conditions.
  • the fluid of stage C may be pumped as a low viscosity fluid and the viscosity of the fluid is increased in the reservoir; in that case, the initial viscosity is greater than about 20 mPa-s at a shear rate 100 s "1 (with a preferred range of from about 20 to about 100 mPa-s at a shear rate of 100 s "1 ) and the final viscosity is greater than about 50 mPa-s, preferably from about 100 to about 1000 mPa-s, at a shear rate of 100 s ⁇ 1 under ambient conditions.
  • the volume of stage C is generally smaller than the volumes of the other stages of the treatment.
  • the ratio of the volumes of fluid in stage C to fluid in stage B is less than about 1/10, preferably from about 1/100 to about 1/10.
  • the upper limit of the total volume of fluid in stage C of each treatment cycle (before treatment redirection to another wellbore interval) is about 64 m 3 (400 bbl); as little as about 10 m 3 of fluid may be used.
  • Fluid C optionally contains a fiber, for example a degradable fiber, and/or a proppant.
  • the preferred proppant size is from about 0.05 mm to about 1 mm (preferably from about 0.2 to about 0.4 mm; the preferred proppant concentration is from about 0.012 to about 0.6 kg added per liter of clean fluid (most preferably from about 0.024 to about 0.24 kg per liter of clean fluid).
  • a particularly suitable method of pumping a low viscosity fluid Stage C and then having the viscosity of the fluid increase in a carbonate-containing reservoir, for example a carbonate-containing shale is the use of an acidic fluid that undergoes an increase in viscosity when the pH is raised, for example by contact with the reservoir rock.
  • Many such systems are known for use in acidizing and acid fracturing; they are commonly called self-diverting acids and when based on viscoelastic surfactants they are called viscoelastic diverting acids. In the present invention, they are used to divert slickwater. Examples are those based on viscoelastic surfactants, for example certain betaines. Suitable viscosifiers and systems are described in U. S.
  • the use of such self-diverting acids in the present invention can further enhance the complexity of fracture networks by introducing heterogeneity by etching the formation and reducing the fracture initiation pressure, and also by selective dissolution of scales, that have usually accumulated in the natural fractures/fissures/fabric of a reservoir.
  • Stage C may also contain fibers, preferably having a diameter of from about 1 to about 100 microns (more preferably from about 10 to about 30 microns) and a length of from about 1 to about 50 mm (preferably from about 3 to about 35 mm) at a concentration of from about 0 to about 60 g per liter of clean fluid, (preferably about 1.2 to about 16 g per liter of clean fluid).
  • Substantially proppant free fluid is defined here as a fluid having a loading of proppant less than about 0.024 kg per liter of clean fluid.
  • the viscous fluid is intended and therefore designed to divert, not to carry proppant or fiber.
  • Stage C fluids are substantially proppant free.
  • Fluids A and B are preferably selected from fresh water, brine, seawater, solutions of polymers, solutions of viscoelastic surfactants, gelled oils, viscosified diesel fuels, emulsions and mixtures of such fluids.
  • Fluid C is preferably chosen from solutions of polymers, gels, cross-linked gels, solutions of viscoelastic surfactants, gelled oils, viscosified diesel fuels, and emulsions. These viscosifiers are preferably degradable.
  • Preferred polymers include guar gum, gum arabic, gum karaya, tamarind gum, locust bean gum, cellulose, xanthan, scleroglucan, polyacrylamide, polyacrylate, combinations of these materials, and modified, substituted or derivatized versions of these polymers.
  • the polymers in the fluids may be crosslinked, for example by compounds of boron, aluminum, titanium, zirconium, chromium, iron, copper, zinc, antimony, organic or inorganic polyions and combination of these materials.
  • the fluids may optionally contain crosslink delay agents or gel or polymer breakers, for example encapsulated gel breakers, internal delayed gel breakers, temperature- activated gel breakers and combination of these.
  • the proppant in fluid B, and optionally in fluid C preferably is selected from sands, ceramics, glasses, rocks and minerals such as mica, organic and inorganic polymers, metals and alloys, composite materials and mixtures of these materials.
  • proppants preferably have shapes selected from spheres, rods, cylinders, plates, sheets, spherocylinders, ellipsoids, toruses, oblongs, fibers, meshes, arches/cells, meshes/cells, honeycombs, bubbles, sponge-like or foam structures, and mixtures of these shapes.
  • "Arches/cells” and “meshes/cells” are special three- dimensional organizations of materials, for example reticulated foamed polyurethane. Such materials have a three-dimensional bubble structure consisting, for example, of dodecahedrons, each face of which is a pentagon. The pentagons are formed by edges between which there is a membrane or window. At least one membrane is always missing, thus forming an open pore structure. Viscosifiers and proppants and methods of preparing these fluids are all known in the art.
  • the proppant in fluids B, and optionally C preferably is in a size range of from about 5 to about 1000 microns, most preferably from about 50 to about 840 microns. These proppants may optionally be coated or may have an organophilic treatment. Fluid B preferably carries at least about 90 weight percent of the proppant in stages B and C.
  • the fluids of stages B and C may optionally also contain degradable materials, for example fibers, plates, flakes, beads and combinations of these materials.
  • the degradable materials are chosen, for example, from polylactic acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, copolymers of lactic acid with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and mixtures of these materials.
  • any of the fluids in particular the fluids used in stages C, may be foamed or energized.
  • the fracture systems formed with water fracs in heterogeneous reservoirs are often believed to have complex and branched structures with many intersecting natural fractures, with changes in fracture direction (see Figure 1 C).
  • the viscosified fluids and methods used in the present invention plug the existing fractures at a considerable distance from the wellbore; this depends on fluid viscosity which in turn may be controlled by a delay agent. By varying the delay time, an operator can control the distance from the wellbore at which the plugging occurs.
  • the plug formed drastically increases the pressure and induces creation of new fractures connected to the same fracture network, growing in other directions, stimulating previously non- treated zones (see Example 2).
  • Stages A (optionally) and B are repeated after each diversion (stage C) to create new fracture(s) and fracture networks.
  • Each pumping of at least a stage B and a stage C (in either order) is called a cycle; each cycle contains at least stages B and C; the entire treatment starts with a stage A.
  • the cycles for example ABC-ABC (preferred), ABC-BC, ABC-BC-BC, ACB-CB-CB, ABC-BAC -BC, or ABC-BC-ABC-BC, etc., are repeated as many times as necessary to develop the fracture network desired.
  • the ratio of the volumes, in any cycle, of fluid in stage C to fluid in stage B is less than about 1/10, preferably from about 1/100 to about 1/10.
  • stage C of each treatment cycle (before treatment redirection to another wellbore interval) is about 64 m 3 (400 bbl); as little as about 10 m 3 of fluid may be used.
  • Any cycle may optionally include a stage A and optionally may be followed by a stage D, in which a gel with coarse (for example from about 0.4 to about 1 mm (preferably from about 0.42 to about 0.84 mm)) proppant is pumped to prop the primary fracture and to ensure that it has a high conductivity.
  • stage D is optionally followed with a stage E, pumping of a proppant flowback control agent, e.g.
  • Water, brine, or a fluid that is the same as or similar to the fluid of any stage A may be used for the flush; the flush is usually about the volume of the wellbore from the wellhead to the top or bottom of the perforated interval being treated (increased or decreased by from about 3 to about 100 bbl (about 18 to about 65 m 3 ).
  • the fluid of any stage D has a viscosity of about 1 to about 1000 mPa-s at a shear rate of 100 s ⁇ 1 ; the fluid of any stage E has a viscosity of about 1 to about 50 mPa-s at a shear rate of 100 s "1 .
  • each stage A, stage B, stage C, stage D, or stage E need not be identical to the fluid of any other stage A, stage B, stage C, stage D, or stage E.
  • the fluid plugs created by stage(s) C for diversion degrade naturally or are destroyed with oxidative or other types of breakers, which reduce the fluid viscosity. This opens the originally fractured regions of the reservoir and provides hydrocarbon or other fluid transport to the wellbore, enhancing production.
  • Example 1 The examples below illustrate the transportability of a viscosified fluid in a slickwater fluid having a similar density (Example 1 ); plugging of a manifold system (which simulates a complex fracture network) with a slug of viscosified fluid (Example 2); and degradation of the plug over time in the presence of an oxidative breaker (Example 3).
  • Example 3 The examples are presented for the purpose of illustrating the preferred embodiments of the invention and do not constitute any limitations to the scope of the invention.
  • Example 1 A fluid slug prepared from a borate cross-linked guar gel, having a guar concentration of 6 g/L (50 lb/1000 gal) was placed in a Plexiglas settling slot with dimensions 1000 ⁇ 300 ⁇ 4 mm, above a slug of similar-density slickwater containing 0.05 weight percent of a polyacrylamide friction reducer. No slug diffusion during the experimental time of 4 hours at room temperature was observed. The viscous slug remained consolidated and floated on the slickwater slug without settling.
  • a viscous slug of a desired composition was loaded into the slug injection loop before the experiment and was isolated from the main line by valves. Base fluid was pumped through the pipe for several minutes until the base fluid flow stabilized. Once flow stabilization was attained, the flow was directed into the slug sample injection loop and a viscous slug was pumped into the system.
  • Viscous fluid slugs were prepared from a borate cross-linked guar gel having a guar concentration of 6 g/L (50 lb/1000 gal) and dyed with phenolphthalein for visualization; a base fluid, slickwater, containing 0.05 wt % of a polyacrylamide friction reducer was used.
  • the slickwater and viscous fluid slugs were pumped and slug stretching during transport inside the tube was studied.
  • the flow rate of the slickwater was 8.1 L/min, which corresponds to a linear velocity of 43.6 cm/sec.
  • the experiment showed that the average viscous fluid slug velocities were 42 cm/sec.
  • the difference between the base fluid and the viscous slug velocities was caused by a fingering effect in which the denser and more viscous fluid was transported with a lower rate relative to the base fluid velocity.
  • the initial slug lengths injected were 215 ⁇ 20 cm.
  • the final slug lengths at the end of the tube were 250 ⁇ 24 cm. No significant slug stretching during transportation inside the tube was observed when the flow was laminar. This experiments shows that it is possible to transport slugs of viscous fluids inside a fracture; the slugs were not significantly dispersed under conditions that mimic the flow conditions inside a fracture.
  • FIG. 3 A manifold [3] as shown in Figure 2 was built using Swagelok tubes with outer diameters varying from 6.35 mm (0.25 in) down to 1.59 mm (1/16 in).
  • Figure 3 shows the test results in which the pressure inside the tube was plotted against time.
  • the same slickwater as used in Examples 1 and 2 was pumped through the manifold with a Knauer pump [1] at 0.5 l/min flow rate with pressures generally not exceeding 138 kPa (20 psi). Slugs of the crosslinked gel used in Examples 1 and 2 were then placed in the slurry tank [2] and the pressure was followed during pumping; the pressure increased up to 1007 kPa (146 psi), at which pressure the pressure relief rapture disk [4] broke.
  • the manifold system emulates a complex fracture network during the diversion stage, and the rupture disk break mimics fracturing of a non-stimulated zone of the reservoir due to the net pressure increase.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Materials Engineering (AREA)
  • Organic Chemistry (AREA)
  • Mining & Mineral Resources (AREA)
  • Geology (AREA)
  • Fluid Mechanics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Physics & Mathematics (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Consolidation Of Soil By Introduction Of Solidifying Substances Into Soil (AREA)
  • Detergent Compositions (AREA)
  • Drilling And Exploitation, And Mining Machines And Methods (AREA)
  • Revetment (AREA)
  • Biological Depolymerization Polymers (AREA)

Abstract

La présente invention concerne un procédé pour dériver de l'eau de nappe injectée dans un traitement de fracturation hydraulique. Le fluide de dérivation est de préférence un fluide visqueux, sensiblement dépourvu d'agent de soutènement, qui entraîne une augmentation de pression nette et le colmatage de certaines des microfractures dans le système de fracture initial créé, ce qui entraîne la formation de microfractures supplémentaires raccordées au réseau de fracture initial et augmente la zone de contact avec la roche de formation. Le procédé génère une complexité de réseau de fracture plus importante et ainsi une zone de contact plus importante avec le réservoir au cours d'un seul cycle de traitement.
PCT/RU2010/000248 2010-05-18 2010-05-18 Procédé de fracturation hydraulique WO2011145966A1 (fr)

Priority Applications (7)

Application Number Priority Date Filing Date Title
US13/698,658 US20130105157A1 (en) 2010-05-18 2010-05-18 Hydraulic Fracturing Method
PCT/RU2010/000248 WO2011145966A1 (fr) 2010-05-18 2010-05-18 Procédé de fracturation hydraulique
CA2799555A CA2799555A1 (fr) 2010-05-18 2010-05-18 Procede de fracturation hydraulique
CN2010800681277A CN103109039A (zh) 2010-05-18 2010-05-18 水力压裂方法
MX2012013299A MX341853B (es) 2010-05-18 2010-05-18 Método de fracturación hidráulica.
RU2012154650/03A RU2523316C1 (ru) 2010-05-18 2010-05-18 Способ гидравлического разрыва пласта
ARP110101681A AR081195A1 (es) 2010-05-18 2011-05-17 Metodo de fracturacion hidraulica

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
PCT/RU2010/000248 WO2011145966A1 (fr) 2010-05-18 2010-05-18 Procédé de fracturation hydraulique

Publications (1)

Publication Number Publication Date
WO2011145966A1 true WO2011145966A1 (fr) 2011-11-24

Family

ID=44991887

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/RU2010/000248 WO2011145966A1 (fr) 2010-05-18 2010-05-18 Procédé de fracturation hydraulique

Country Status (7)

Country Link
US (1) US20130105157A1 (fr)
CN (1) CN103109039A (fr)
AR (1) AR081195A1 (fr)
CA (1) CA2799555A1 (fr)
MX (1) MX341853B (fr)
RU (1) RU2523316C1 (fr)
WO (1) WO2011145966A1 (fr)

Cited By (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013155307A3 (fr) * 2012-04-12 2014-01-09 Baker Hughes Incorporated Procédé consistant à augmenter la perméabilité d'une formation souterraine en générant un réseau de multiples fractures
WO2016074075A1 (fr) * 2014-11-10 2016-05-19 Dusseault Maurice B Procédé d'injection de fracture à plusieurs étapes pour une meilleure production de ressources à partir de schistes
WO2017135840A1 (fr) * 2016-02-04 2017-08-10 Schlumberger Canada Limited Additif à fibres polymères pour la prévention du reflux d'agent de soutènement
US10001003B2 (en) 2010-12-22 2018-06-19 Maurice B. Dusseault Multl-stage fracture injection process for enhanced resource production from shales
CN109931045A (zh) * 2017-12-18 2019-06-25 中国石油化工股份有限公司 一种双缝系统的自支撑酸压方法
RU2710575C2 (ru) * 2015-02-17 2019-12-27 Ламберти Спа Ингибиторы сланцев на основе катионной тамариндовой камеди и буровой раствор, содержащий ингибитор сланцев
RU2816923C1 (ru) * 2022-07-29 2024-04-08 Саусвест Петролиэм Юниверсити Способ кислотного гидроразрыва пласта в обратной последовательности для карбонатных пластов

Families Citing this family (32)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CA2775787C (fr) * 2010-12-22 2013-05-21 Maurice B. Dusseault Procede fracturation hydraulique multietapes concu pour ameliorer la production de ressources a partir des schistes
US20140299318A1 (en) * 2013-04-05 2014-10-09 Baker Hughes Incorporated Method of increasing fracture network complexity and conductivity
CA2922265C (fr) * 2013-09-23 2018-12-04 Halliburton Energy Services, Inc. Amelioration de la fracturation et reseaux de fracturation complexes dans des formations impermeables
CN103642474B (zh) * 2013-11-21 2017-02-08 东方宝麟科技发展(北京)有限公司 水力压裂用低伤害胶塞稠化剂与胶塞组合物及其应用
US9366124B2 (en) * 2013-11-27 2016-06-14 Baker Hughes Incorporated System and method for re-fracturing multizone horizontal wellbores
CN103756664B (zh) * 2014-01-21 2017-01-25 东方宝麟科技发展(北京)有限公司 页岩气压裂液用稠化剂、压裂液及其制备方法与应用
US20150345268A1 (en) * 2014-05-27 2015-12-03 Statoil Gulf Services LLC Applications of ultra-low viscosity fluids to stimulate ultra-tight hydrocarbon-bearing formations
CN104004506B (zh) * 2014-06-18 2016-08-17 西安石油大学 一种适合非常规储层压裂用无水压裂液及其制备方法
AU2014405605B2 (en) * 2014-09-02 2017-10-05 Halliburton Energy Services, Inc. Enhancing complex fracture networks in subterranean formations
WO2016053345A1 (fr) * 2014-10-03 2016-04-07 Halliburton Energy Services, Inc. Microsphères de cendres volantes pour utilisation dans des opérations de formations souterraines
CN105986802B (zh) * 2015-02-13 2018-12-25 中国石油天然气股份有限公司 井下压裂的方法
US10577909B2 (en) * 2015-06-30 2020-03-03 Halliburton Energy Services, Inc. Real-time, continuous-flow pressure diagnostics for analyzing and designing diversion cycles of fracturing operations
CN105041288A (zh) * 2015-07-13 2015-11-11 中国石油大学(北京) 一种碳酸盐岩油气藏裂缝转向酸压方法
CN105114050B (zh) * 2015-09-15 2018-05-25 中国石油大学(北京) 一种新型压裂泵注方法
WO2017052522A1 (fr) * 2015-09-23 2017-03-30 Halliburton Energy Services, Inc. Amélioration de réseaux de fractures complexes dans des formations souterraines
CN105201478A (zh) * 2015-09-30 2015-12-30 大庆井泰石油工程技术股份有限公司 油气井缝网体系压裂工艺
CN106567702B (zh) * 2015-10-10 2021-08-06 中国石油化工股份有限公司 一种提高深层页岩气裂缝复杂性指数的方法
CN106907137B (zh) * 2015-12-23 2019-01-01 中国石油化工股份有限公司 一种页岩油藏体积压裂裂缝有效导流的方法
US10900318B2 (en) * 2016-04-07 2021-01-26 Halliburton Energy Services, Inc. Pressure-exchanger to achieve rapid changes in proppant concentration
US10125594B2 (en) * 2016-05-03 2018-11-13 Halliburton Energy Services, Inc. Pressure exchanger having crosslinked fluid plugs
US11136494B2 (en) * 2016-06-02 2021-10-05 Rockwater Energy Solutions, Llc Polymer with internal crosslinking and breaking mechanisms
RU2655513C2 (ru) * 2016-10-13 2018-05-28 Шлюмберже Текнолоджи Б.В. Способ гидроразрыва углеводородного пласта
CA3054016C (fr) 2017-04-12 2021-07-13 Halliburton Energy Services,Inc. Soutenement etage de reseaux de fractures
CN107387053B (zh) * 2017-06-13 2020-05-22 北京大学 一种大通道主裂缝与复杂缝网协同压裂的方法
WO2019147283A1 (fr) * 2018-01-29 2019-08-01 Halliburton Energy Services, Inc. Fluides de traitement contenant des fibres dégradables greffées avec un agent de réticulation
US11608468B2 (en) * 2018-10-18 2023-03-21 Basf Se Process of fracturing subterranean formations
US10920558B2 (en) 2019-07-12 2021-02-16 Halliburton Energy Services, Inc. Method of enhancing proppant distribution and well production
RU2734892C1 (ru) * 2020-05-12 2020-10-26 Алексей Владимирович Лысенков Способ проведения гидравлического разрыва пласта
CN113847005B (zh) * 2020-06-28 2024-03-08 中国石油化工股份有限公司 一种利用温敏型泡沫压裂液进行重复压裂的方法及应用
CN114059980B (zh) * 2020-07-29 2024-03-26 中国石油化工股份有限公司 一种页岩储层压裂方法
CN114458271A (zh) * 2020-10-22 2022-05-10 中国石油化工股份有限公司 一种提高深层高脆性页岩气裂缝复杂性的方法及应用
CN114810020A (zh) * 2021-01-19 2022-07-29 中国石油化工股份有限公司 一种多簇裂缝均匀延伸的压裂方法及应用

Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4143715A (en) * 1977-03-28 1979-03-13 The Dow Chemical Company Method for bringing a well under control
US5460225A (en) * 1994-07-18 1995-10-24 Shell Oil Company Gravel packing process
RU2256786C2 (ru) * 2002-04-19 2005-07-20 Шлюмбергер Текнолоджи Бв Способ расклинивания трещины в подземном пласте (варианты) и способ гидроразрыва в подземном пласте

Family Cites Families (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3592266A (en) * 1969-03-25 1971-07-13 Halliburton Co Method of fracturing formations in wells
US3688843A (en) * 1970-11-16 1972-09-05 Atomic Energy Commission Nuclear explosive method for stimulating hydrocarbon production from petroliferous formations
US3974077A (en) * 1974-09-19 1976-08-10 The Dow Chemical Company Fracturing subterranean formation
US6776235B1 (en) * 2002-07-23 2004-08-17 Schlumberger Technology Corporation Hydraulic fracturing method
US6814144B2 (en) * 2002-11-18 2004-11-09 Exxonmobil Upstream Research Company Well treating process and system
US7726399B2 (en) * 2004-09-30 2010-06-01 Bj Services Company Method of enhancing hydraulic fracturing using ultra lightweight proppants
US7506689B2 (en) * 2005-02-22 2009-03-24 Halliburton Energy Services, Inc. Fracturing fluids comprising degradable diverting agents and methods of use in subterranean formations
CN101457640B (zh) * 2007-12-14 2012-03-14 中国石油大学(北京) 磨料射流井下射孔、割缝分层压裂的方法

Patent Citations (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4143715A (en) * 1977-03-28 1979-03-13 The Dow Chemical Company Method for bringing a well under control
US5460225A (en) * 1994-07-18 1995-10-24 Shell Oil Company Gravel packing process
RU2256786C2 (ru) * 2002-04-19 2005-07-20 Шлюмбергер Текнолоджи Бв Способ расклинивания трещины в подземном пласте (варианты) и способ гидроразрыва в подземном пласте

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
S. A. RYABOKON.: "Tekhnologicheskie zhidkosti dlya zakachivaniya i remonta skvazhin.", MONOGRAFIYA, OAO NPO "BURENIE", 2006, pages 120 - 127, 143-146 *

Cited By (10)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US10001003B2 (en) 2010-12-22 2018-06-19 Maurice B. Dusseault Multl-stage fracture injection process for enhanced resource production from shales
WO2013155307A3 (fr) * 2012-04-12 2014-01-09 Baker Hughes Incorporated Procédé consistant à augmenter la perméabilité d'une formation souterraine en générant un réseau de multiples fractures
EP2836676A4 (fr) * 2012-04-12 2016-07-27 Baker Hughes Inc Procédé consistant à augmenter la perméabilité d'une formation souterraine en générant un réseau de multiples fractures
WO2016074075A1 (fr) * 2014-11-10 2016-05-19 Dusseault Maurice B Procédé d'injection de fracture à plusieurs étapes pour une meilleure production de ressources à partir de schistes
RU2710575C2 (ru) * 2015-02-17 2019-12-27 Ламберти Спа Ингибиторы сланцев на основе катионной тамариндовой камеди и буровой раствор, содержащий ингибитор сланцев
WO2017135840A1 (fr) * 2016-02-04 2017-08-10 Schlumberger Canada Limited Additif à fibres polymères pour la prévention du reflux d'agent de soutènement
US11370960B2 (en) 2016-02-04 2022-06-28 Schlumberger Technology Corporation Polymer fiber additive for proppant flowback prevention
CN109931045A (zh) * 2017-12-18 2019-06-25 中国石油化工股份有限公司 一种双缝系统的自支撑酸压方法
CN109931045B (zh) * 2017-12-18 2021-08-31 中国石油化工股份有限公司 一种双缝系统的自支撑酸压方法
RU2816923C1 (ru) * 2022-07-29 2024-04-08 Саусвест Петролиэм Юниверсити Способ кислотного гидроразрыва пласта в обратной последовательности для карбонатных пластов

Also Published As

Publication number Publication date
RU2523316C1 (ru) 2014-07-20
CA2799555A1 (fr) 2011-11-24
RU2012154650A (ru) 2014-06-27
MX2012013299A (es) 2013-02-15
AR081195A1 (es) 2012-07-04
MX341853B (es) 2016-09-05
US20130105157A1 (en) 2013-05-02
CN103109039A (zh) 2013-05-15

Similar Documents

Publication Publication Date Title
US20130105157A1 (en) Hydraulic Fracturing Method
CA2995588C (fr) Amelioration de reseaux de fractures complexes dans des formations souterraines, transport sequentiel de materiaux particulaires
CA2995600C (fr) Amplification de geometrie de fracture complexe dans des formations souterraines et fracturation sequentielle
US20140144635A1 (en) Methods of Enhancing Fracture Conductivity of Subterranean Formations Propped with Cement Pillars
US20160319185A1 (en) Shear thickening fluid method and system to deliver materials downhole
US20140144633A1 (en) Methods of Enhancing Fracture Conductivity of Subterranean Formations Propped with Cement Packs
US20150053403A1 (en) In situ channelization method and system for increasing fracture conductivity
US20140144634A1 (en) Methods of Enhancing the Fracture Conductivity of Multiple Interval Fractures in Subterranean Formations Propped with Cement Packs
CA2995069C (fr) Amelioration de reseaux de fractures complexes dans des formations souterraines
WO2015148151A1 (fr) Traitement de puits
US20150369028A1 (en) Compound cluster placement in fractures
CA3027352C (fr) Fluides de traitement a gaz liquide a utiliser dans des operations de formation souterraine
US20140131042A1 (en) Methods for Generating Highly Conductive Channels in Propped Fractures
US10364660B2 (en) Proppant-free channels in a propped fracture using ultra-low density, degradable particulates
NO20161945A1 (en) Compound cluster placement in fractures
CA3054016C (fr) Soutenement etage de reseaux de fractures
EP2928983A1 (fr) Procédés de traitement d'une formation souterraine à l'aide de compositions de résine furannique en une étape
US20220049153A1 (en) Sand Consolidation Compositions And Methods Of Use
WO2020131122A1 (fr) Formation de massifs de fracturation dans des formations à haute perméabilité

Legal Events

Date Code Title Description
WWE Wipo information: entry into national phase

Ref document number: 201080068127.7

Country of ref document: CN

121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 10851850

Country of ref document: EP

Kind code of ref document: A1

ENP Entry into the national phase

Ref document number: 2799555

Country of ref document: CA

WWE Wipo information: entry into national phase

Ref document number: MX/A/2012/013299

Country of ref document: MX

NENP Non-entry into the national phase

Ref country code: DE

WWE Wipo information: entry into national phase

Ref document number: 13698658

Country of ref document: US

ENP Entry into the national phase

Ref document number: 2012154650

Country of ref document: RU

Kind code of ref document: A

122 Ep: pct application non-entry in european phase

Ref document number: 10851850

Country of ref document: EP

Kind code of ref document: A1