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WO2010068128A1 - Régulation de la croissance en hauteur de fractures hydrauliques - Google Patents

Régulation de la croissance en hauteur de fractures hydrauliques Download PDF

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Publication number
WO2010068128A1
WO2010068128A1 PCT/RU2008/000756 RU2008000756W WO2010068128A1 WO 2010068128 A1 WO2010068128 A1 WO 2010068128A1 RU 2008000756 W RU2008000756 W RU 2008000756W WO 2010068128 A1 WO2010068128 A1 WO 2010068128A1
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WO
WIPO (PCT)
Prior art keywords
fluid
particles
barrier
fracture
viscosity
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PCT/RU2008/000756
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English (en)
Inventor
Andrei Alexandrovich Osiptsov
Oleg Olegovich Medvedev
Dean Willberg
Original Assignee
Schlumberger Canada Limited
Services 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, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited filed Critical Schlumberger Canada Limited
Priority to US12/998,866 priority Critical patent/US20110272159A1/en
Priority to PCT/RU2008/000756 priority patent/WO2010068128A1/fr
Priority to CA2746368A priority patent/CA2746368A1/fr
Publication of WO2010068128A1 publication Critical patent/WO2010068128A1/fr

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    • 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
    • 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
    • E21B43/27—Methods for stimulating production by forming crevices or fractures by use of eroding chemicals, e.g. acids
    • 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
    • C09K2208/08—Fiber-containing well treatment fluids

Definitions

  • Fracture height control is a common challenge faced by operators designing hydraulic fracture treatments, particularly in low permeability reservoirs.
  • a fracture is initiated in a productive interval, it grows in all directions until it reaches an interface, for example with upper and lower formations in the common case of a vertical fracture in a horizontal reservoir, and encounters a resistance to its growth.
  • the surrounding rock contacting the productive formation is tougher and less permeable than the reservoir. If natural barriers exist above and below the reservoir, the vertical growth of the fracture will be restrained and the fracture will propagate within the productive zone. This provides an efficient fracture with the entire surface lying inside the reservoir.
  • US Patent Application Publication No. 2005/0016732 describes a method of hydraulically fracturing in two principal steps.
  • a fracture in and below the productive zone of a formation is initiated by introducing a fluid free of a proppant.
  • proppant-laden slurry that contains a relatively lightweight density proppant is introduced into the subterranean formation. Either the fluid density of the proppant-free fluid is greater than the fluid density of the proppant-laden slurry or the viscosity of the proppant- free fluid is greater than the viscosity of the proppant laden slurry.
  • the method limits undesirable fracture height growth in the hydrocarbon-bearing subterranean formation during the fracturing.
  • US Patent 4,478,282 describes a method of hydraulically fracturing an underground formation penetrated by a wellbore involving injecting a fracturing fluid pad into the formation, then injecting a non-proppant fluid stage that is a transport fluid and contains a flow block material, the flow block material being sand and silica flour with a particle size distribution of the sand of 10-20, 20-40, and 100 mesh and of the silica flour of 200 mesh, and then injecting a proppant laden fluid slurry into the formation.
  • the method relies on the assumption that the fracture growing into adjacent shale formations is narrower than in the productive formation and so the flow block material will bridge out in the fracture in the shale. Consequently, one aspect of that invention is that conditions that promote fracture height growth were actually preferred. Fluid viscosities were not considered important.
  • a first embodiment of the Invention is a method for creating a fracture, in a subterranean formation, having a barrier to fluid flow out of the top or bottom or both the top and bottom of the fracture; the barrier contains particles.
  • the method includes the steps of (a) injecting a pad fluid having a viscosity that allows settling or rising of barrier particles toward the top or bottom to form the barrier, (b) injecting a slurry of the barrier particles in a fluid of a viscosity higher than the pad fluid (the fluid being capable of transporting the barrier particles), and (c) injecting a fluid having a lower viscosity than the fluid of step (b) through which the particles may settle or rise to form the barrier.
  • the ratio of the particle density to the densities of the particle- and/or proppant-free fluids is in the range of from about 1.0 to about 5.0, preferably in the range of from about 2.5 to about 5.0.
  • the ratio of the particle density to the densities of the particle- and/or proppant-free fluids is in the range of from about 0.2 to about 1.0, preferably about 0.5 to about 1.0.
  • the particles may be a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0 and particles having a ratio of the particle density to the fluid density in the range of from about 1.0 to about 5.0.
  • the method may also include a step of injecting, between steps (b) and (c), and/or after step (c), a fluid capable of transporting the particles.
  • at least a portion of the particles adheres to one another after placement.
  • At least a portion of the particles may dissolve after the treatment.
  • at least a portion of the particles releases acid after the treatment.
  • At least a portion of the particles may release a breaker after the treatment.
  • one or more of the fluids contains fibers.
  • one or more of the fluids contains a fluid loss control additive. The steps indicated may be followed by a shut in period.
  • Another embodiment of the Invention is a method for creating a fracture, in a subterranean formation, having a barrier to fluid flow and/or fracture growth out of both the top and bottom of the fracture; the barrier contains particles.
  • the method includes the steps of (a) injecting a pad fluid having a viscosity that does not allow settling or rising of barrier particles toward the top or bottom during the treatment, (b) injecting the barrier particles in a fluid capable of transporting the barrier particles, and (c) injecting a fluid having a lower viscosity than the fluid of step (b) through which the particles may settle or rise to form the barrier.
  • the fluids of steps (a) and (b) may have the same viscosity, or all three fluids may have the same viscosity.
  • the ratio of the particle density to the densities of the particle- and/or proppant-free fluids may be in the range of from about 1.0 to about 5.0, preferably in the range of from about 2.5 to about 5.0.
  • the ratio of the particle density to the densities of the particle- and/or proppant-free fluids may be in the range of from about 0.2 to about 1.0, preferably about 0.5 to about 1.0.
  • the particles may also be a mixture of particles having a ratio of the particle density to the fluid density in the range of from about 0.2 to about 1.0 and particles having a ratio of the particle density to the fluid density -in the range of from about
  • the method may further include a step of injecting, between steps (b) and (c), and/or after step (c), a fluid capable of transporting the particles.
  • a fluid capable of transporting the particles.
  • at least a portion of the particles adheres to one another after placement.
  • At least a portion of the particles may dissolve after the treatment.
  • at least a portion of the particles releases acid after the treatment.
  • At least a portion of the particles may release a breaker after the treatment.
  • one or more of the fluids contains fibers.
  • one or more of the fluids contains a fluid loss control additive. The steps indicated may be followed by a shut in period.
  • Figure 1 shows the results of a process for placing a particle slug at the bottom of a fracture.
  • Figure 2 shows the results of a process for placing a particle slug at the top of a fracture.
  • Figure 3 shows the results of a process for placing a particle slug at the top and at the bottom of a fracture.
  • Figure 4 shows the results of a process for placing a particle slug that extends deep into a fracture at the bottom.
  • Figure 5 shows the results of a process for placing a particle slug that extends deep into a fracture at the top.
  • Figure 6 shows the results of a process for placing a particle slug that extends deep into a fracture both at the bottom and at the top.
  • Figure 7 shows results calculated with a simulator of a method for placing a particle slug at the bottom of a fracture.
  • Figure 8 shows results calculated with a simulator of a method for placing an extended particle slug at the bottom of a fracture.
  • Figure 9 shows results calculated with a simulator of a method for placing extended particle slugs at the bottom and top of a fracture.
  • Figure 10 shows results calculated with a simulator of a method for placing an extended particle slug at the bottom of a fracture at very low injection rates.
  • the barrier is a barrier to fluid flow and a barrier to fracture growth.
  • the method is based essentially on the two following phenomena: the gravitational settling (or rising) of particles in a fluid, and the penetration of a finger of a low-viscosity fluid into a high-viscosity fluid in a slot, for example a fracture, according to the Saffman-Taylor instability mechanism.
  • the process of the barrier placement consists of three necessary stages: (i) the injection of a first relatively low-viscosity particle-free fluid, (ii) then the injection of a thickened barrier-particle-laden fluid, and then (iii) injection of a second relatively low- viscosity particle-free fluid.
  • particle-free we mean not containing sufficient particles to contribute significantly to formation of a barrier; we do not mean that the fluid may not contain any particles of any type; for example, a pad fluid may contain fluid loss particles that are not major contributors, for example greater than 20%, to the barrier.
  • the fluids injected before and after the particle-laden slug provide a relatively low-viscosity medium, in which the slug sediments rapidly to the fracture bottom (or rises rapidly to the fracture top).
  • first low-viscosity fluid we mean that the fluid has a viscosity sufficiently low that the particles will rise or fall through it to the location required in the time allowed by the pumping schedule and any optional shut in.
  • the low- viscosity fluid injected after the slug cuts the highly-viscous particle-laden fluid into two unequal parts according to the Saffman-Taylor instability mechanism, displacing the lower, larger, part of the slug to the fracture bottom, thereby enhancing the sedimentation of a lumped barrier.
  • the lower portion is larger because of gravitational settling of individual proppant particles towards the bottom of the fracture.
  • low-viscosity fluid when we describe the second low- viscosity fluid as having a "low viscosity”, we mean that it fingers through the thickened particle-laden fluid under the pumping conditions, and when we describe the particle-laden fluid as "thickened” or “highly-viscous”, we mean that the second low-viscosity fluid will finger through it under the pumping conditions.
  • Low-viscosity fluids have been used in the past to provide particle settling or rising in fracturing, but not to cut a particle-laden fracturing fluid into portions for the purpose of forming fluid flow and fracture growth barriers.
  • stretched barrier is required (a barrier extending farther out into the fracture from the wellbore in which the fracture is being created than would occur without the auxiliary stage), then an auxiliary stage is introduced between the injection of the slug and the injection of the second low-viscosity fluid.
  • the auxiliary stage is the injection of a highly-viscous particle- free fluid. This fluid bulldozes the particle-laden slug along the fracture (at the top, the bottom, or both) thereby providing an extended barrier, which bridges along a greater portion of the fracture.
  • the auxiliary stage fluid as being “highly-viscous” we mean that it is sufficiently viscous to be able to push the barrier particles farther into the fracture.
  • This method and fluid system for barrier placement assisted by gravitational settling or rising and by an unstable fluid-fluid displacement in a hydraulic fracture makes it possible to control the fracture height growth and to prevent the fracture from propagating into the undesired zones located either above or below the target formation.
  • the method and fluids allow the operator to keep a fracture in an oil-bearing formation and avoid water- or gas-bearing regions.
  • the process of placing an extended barrier at the top or bottom of a fracture includes four stages of injecting different fluids into the subterranean formation.
  • the stages are as follows: (i) the injection of a pad of a low- viscosity particle-free fluid into a well in order to open and propagate the hydraulic fracture in the subterranean formation, (ii) then the injection of a more viscous particle-laden fluid, (iii) then the injection of a low-viscosity particle-free fluid, and then (iv) the injection of a highly-viscous particle-free fluid.
  • the particle-free pad injected in the first stage provides a low-viscosity medium, in which the slug sediments rapidly to the fracture bottom or rises rapidly to the fracture top. In such cases the pad fluid must have a lower viscosity than that of the fluid used to place the barrier particles.
  • the pad fluid must have a sufficiently low viscosity to allow the barrier to settle (or rise), but at the same time it must have a sufficiently high viscosity to open and propagate a fracture, so there must be a balance.
  • the pad fluid will commonly have a fairly high viscosity and in such cases the stage or stages after the barrier injection stage must be long enough, or there must be a shut in period, to allow the time necessary for the barrier to rise or fall in a viscous environment.
  • Suitable viscosities, stage volumes, optional shut in periods, and pumping rates may be calculated by those skilled in fracturing, for example by using one of the many numerical simulators available.
  • a conventional fracturing treatment may begin right after the end of stage (iv), or optionally the well may be shut in to allow additional time for the barrier particles to rise or fall to form the barrier(s).
  • the treatment is designed so that the barrier particles form a barrier by the end of the injection of the last stage before initiation of a conventional fracture treatment, or, if shut in is necessary (because of the need for time for settling (rising) or for any other operational reasons), by the end of the shut in period.
  • the barrier is considered to have been formed when flow out of the top or bottom or both the top and bottom of the fracture has been inhibited such that fracture growth past the barrier does not occur.
  • the first stage may be a highly- viscous fluid.
  • the finger of the low- viscosity fluid injected during the third stage cuts the slug into two almost equal parts and displaces the lower and the upper parts downwards and upwards, thereby providing the placement of two barriers, one at the top and one at the bottom of the fracture.
  • This particulate material may consist of small rigid or deformable particles of any shape with the density higher or lower than that of any of the injected fluids.
  • the particles may or may not adhere to one another and/or the surrounding rock after placement, may or may not dissolve in the fluid, and may or may not release acid to etch the surrounding formation. This will be discussed further below; these actions may be instigated by the action of a physical trigger (which may for example be closure stress, a temperature increase, a pH change, contact with water, etc.).
  • the Io w- viscosity particle-free fluid injected at the third stage penetrates into the slug according to the Saffman-Taylor instability mechanism, cuts the slug into two unequal parts, and in the case of heavy barrier particles displaces the lower bigger part of the slug towards the fracture bottom thereby enhancing the sedimentation of the slug.
  • the following guidelines are followed for a successful barrier placement:
  • the flow rate should be the minimum possible, for example as low as about 3.2 m 3 /min, although this may favor screening out;
  • the density of the particles constituting the barrier should be high (for a barrier at the bottom of the fracture) relative to that of the fluid, for example up to about 3600 kg/m 3 , although this may favor screening out;
  • the particle diameter should be approximately that of conventional proppant or smaller to minimize the risk of a screenout
  • the barrier particle concentration in the slug may be as high as practical, for example up to about 1000 kg/m , to promote efficiency and to promote fast barrier particle settling (rising); the upper limit is governed by equipment limitations and prevention of a screenout (depending upon the other job design parameters);
  • the viscosity of the low- viscosity fluid should be as low as possible without promoting a screenout
  • the barrier placement job consists of three or four stages (exemplary amounts of fluids and particles are given in the examples following this section) in the following order (optionally, additional stages may be added, or stages may be divided into sub-stages, for example as shown in the examples); a specific design is determined, for example, from a series of numerical simulations with a fracture simulator:
  • the pad fluid should, on the contrary, be higher-viscosity; when it is necessary for the pad to have higher viscosity (to initiate and propagate a fracture) than would be desirable for the barrier placement, the pad may contain a breaker, for example a fast-acting breaker; the suitable balance between a viscosity sufficiently high to initiate and propagate a fracture and sufficiently low to allow barrier particle settling(rising) may be determined by numerical simulation; the volume of the pad should be sufficient to create a fracture of desired length;
  • the particle concentration is high, for example up to about 8 PPA in oilfield units (about 0.96 kg/L); barrier placement will generally lead to increased fracture width and decreased likelihood of screenout in the subsequent fracturing treatment; the volume should be sufficient to create a barrier of the desired length along the fracture;
  • a clean highly-viscous fluid for example a cross-linked gel
  • stretch the slug along the fracture so that it will settle (or rise) and form a barrier bridging along the entire lower (or upper) edge of the fracture
  • this stage may be omitted; the volume needed is the volume sufficient to push the barrier to the desired location, or to stretch the barrier over a desired distance along the bottom of fracture;
  • a portion of a low-viscosity fluid for example the same as the pad fluid
  • a low-viscosity fluid for example the same as the pad fluid
  • the Saffman- Taylor instability mechanism to displace at least the larger lower part of the slug towards the fracture bottom, or, if the particles are less dense than the fluid, to displace at least the larger portion towards the top
  • the pad fluid is highly-viscous, then the slug is cut into two almost equal parts displaced upwards and downwards, which results in the placement of two barriers, on the top and the bottom of the fracture, respectively; the volume of clean lower- viscosity fluid is determined by the time needed for the barrier to settle (rise).
  • oilfield fluid may be used for the lower- viscosity and higher- viscosity fluids of the methods of the Invention.
  • the viscosity suitable for a specific job is determined by simulation, for example by comparing and contrasting a series of simulations.
  • the fluids may be oil-based or water-based and may be foamed or energized. Most commonly, the fluids are polymer viscosified water based fluids or viscoelastic surfactant (or other non-polymeric viscosif ⁇ er) viscosified water-based fluids. If made with polymers, a convenient method is to use the same polymer concentration in each fluid but to crosslink the higher-viscosity fluid. The crosslinking may optionally be delayed; the fluids may optionally contain breakers.
  • the fluids may contain any of the additives normally found in oilfield fluids, such as, but not limited to, iron control agents, clay control agents, stabilizers, demulsif ⁇ ers, buffers, etc.
  • any particles used in the oilfield as a proppant, lost circulation, or fluid loss control additive may be used as the barrier particles.
  • Mixtures of particles may be used.
  • Particularly suitable are those normally used as proppants, for example, sand, ceramics, plant matter, polymer beads, glass, hollow glass microspheres.
  • Other particularly suitable materials are those normally used as fluid loss control agents such as calcium carbonate flakes and polyester flakes, for example polyglycolic acid or polylactic acid flakes.
  • the choice of particle material (density, shape, size) is based primarily on the settling (rising) rate, fracture width, fluid viscosities, and screenout potential.
  • the nature of the particles, and their amount and concentration, are preferably selected so that the barrier formed has a permeability between about 0.0 and about 1.0 Darcy.
  • At least a portion of the barrier particles may optionally be selected, or treated, so that they adhere to one another after they are placed. For example, there are many resin coated proppants available that have this property. At least a portion of the barrier particles may optionally be slowly soluble (or hydrolysable) in the fracture fluid or the formation fluid or produced so that they survive long enough to prevent fracture height growth but then dissolve (or hydrolyze) so that they no longer inhibit flow into (or out of) the fracture. For example, the barrier should be gone within a week or a month. Optionally, only a portion of the barrier is subsequently removed, by the same mechanism(s) and over the same time scale. This increases the barrier permeability and so increases the fracture conductivity.
  • Partial or complete removal of the barrier may be initiated by any of a number of triggers, including, by example, closure stress, temperature, pressure, pH change, contact with reservoir fluid, water or another substance, etc.
  • At least a portion of the barrier particles may optionally be an acid- precursor, such as polylactic acid or polyglycolic acid that releases an acid that may etch carbonate formations.
  • the acid may, for example, differentially etch the fracture faces so that they leave a flow path when the fracture closes, or it may etch cavities into the surrounding formation; either increases the fracture conductivity.
  • the barrier particles may optionally contain an acid in a protective coating that, for example, under pressure, increased temperature, or in the presence of water, releases the acid, for the same purposes.
  • At least a portion of the barrier particles may optionally be or include a breaker for the viscosifier used in the fracture fluid used in the subsequent fracturing treatment; this breaker may be released after the fracturing treatment to help break the fracturing fluid, thereby decreasing its viscosity and providing a more efficient fracture cleanup.
  • the breaker may optionally also be a breaker for the viscosifier(s) used in the fluid(s) used to place the barrier.
  • the barrier particles may be rigid or deformable and may be of any shape.
  • a barrier may be placed at the bottom of a fracture by the sequential injection of a lower- viscosity particle-free pad, then a higher-viscosity particle-laden thickened fluid, and then a lower-viscosity particle- free fluid, into the subterranean formation.
  • the conventional fracturing treatment may begin immediately after the end of the final stage of the barrier placement stage sequence.
  • the apparent viscosity of the lower- viscosity fluids should be significantly lower than that of the higher-viscosity fluid at any shear rate.
  • the lower-viscosity fluids may be the same or different in composition and in rheology.
  • the ratio of the particle density to the fluid density ranges from between about 1.0 and about 5.0 (preferably between about 2.5 and about 5.0 to promote settling)
  • this sequential injection of fluids results in the placement of a "lumped" barrier (most of the barrier material is near the wellbore) at the bottom of the fracture as shown in Figure 1, where the wellbore is shown at [1], the fracture is shown at [2], and the barrier is shown at [3].
  • the placement of these barriers is enhanced by the phenomenon of the fluid/fluid displacement; gravitational settling alone would not be sufficient.
  • the relative sizes of the top and bottom barriers may be adjusted by adjusting the relative densities of the particles and the fluid, and the relative viscosities of the different fluids.
  • Barriers may also be placed at both the top and the bottom of the fracture at the same time by the sequential injection of a lower-viscosity particle-free pad, then a higher-viscosity particle-laden thickened fluid, and then a lower-viscosity particle-free fluid, where the particulate material includes a mixture of (a) particles having a ratio of the particle density to the fluid density ranging between about 1.0 and about 5.0 and (b) particles having a ratio of the particle density to the fluid density ranging from about 0.2 and about 1.0.
  • an additional stage of a highly-viscous fluid may be added between the stage of barrier particle injection and the subsequent stage of lower- viscosity fluid.
  • the fluid in this additional stage is a particle-free material, for example a cross-linked gel.
  • the viscosity of the fluid used in this stage is lower than, equal to, or slightly higher than that of the fluid used to inject the particles, but it is highly viscous and is more viscous than the subsequent stage of lower-viscosity fluid.
  • the barrier placement method of the Invention may be applied during a conventional fracturing treatment if the operator determines that undesirable fracture growth is occurring.
  • the conventional treatment is stopped, with or without fracture closure and/or shut in, the barrier is placed with the various stages as detailed above, the fracture is optionally allowed to close and/or is optionally shut in, and then the fracture treatment is resumed, optionally with modifications to the original pumping schedule.
  • concentrations of components such as viscosifiers, proppant (barrier particles), crosslinkers, and breakers
  • concentrations of components may differ in some or all the barrier placement stages from those in any of the fracturing treatment stages and still use chemicals and equipment on hand.
  • Fibers may be added to any of the fluids used in the barrier placement method of the Invention. Fibers in the pad and in the lower-viscosity fluid injected after the barrier particle slug may inhibit settling (or rising) and may not be desirable unless they are needed for some other purpose, for example the breaker or an acid precursor is in the form of fibers. Fibers (or other proppant retention means) in the barrier particle slug may be used to hold the barrier in place during the subsequent fracture treatment, and to adjust the relative rates of barrier particle settling (rising) and barrier particle transport. Fluid loss control additives may be added to any of the stages used for barrier placement; they would be most advantageous in the pad when a large wide fracture is desired.
  • the method of the Invention When the method of the Invention is applied to a vertical fracture (long axis vertical or having a significant vertical component), for example created from a horizontal well, gravity- driven placement of a barrier particle slug results in barrier particle placement at the tip(s) of the fracture, preventing fracture length growth and promoting fracture width growth and keeping the fracture in the formation.
  • the method of the Invention may be applied to fractures in deviated wells.
  • the method of the Invention may be applied in any situation in which a fracture of any orientation has a vertical component and the operator wishes to limit fracture growth upwards or downwards or wishes to create a wide fracture.
  • the method of the Invention may be used before or during acid fracturing treatments, or fracture treatments with other formation-dissolving fluids.
  • the fluids used in the barrier placement process may or may not contain an acid or formation-dissolving fluid.
  • the method of the Invention may be used before or during a slickwater treatment, provided that the equipment available can create and pump fluids having high particle concentrations and can formulate higher-viscosity fluids. If only slickwater fluids and pump rates can be used, it is still possible to create barriers by the method of the Invention if the pumping times of the barrier particle stage and subsequent stages are long enough to allow sufficient particles to be placed and to allow sufficient particle settling (rising).
  • the method of the Invention may be used before frac-pack treatments (fracturing and gravel packing in a single treatment) without deleteriously affecting the frac-pack; normally this would be unnecessary, but it may be done, for example, if the operator plans a fracture treatment and then part way through the treatment changes it to a frac-pack.
  • Table 1 shows the pumping schedule and Figure 1 demonstrates the particle concentration distribution after the end of stage 4, calculated (as in all the examples) using a pseudo 3D fracturing simulator (fracture design, prediction, evaluation and treatment- monitoring program) commercially available under the trade designation FracCADETM from Schlumberger Technology Corporation, Sugar Land, Texas, U. S. A.
  • the density of the barrier particles (called sand in this and the other examples) was equal to 3600 kg/m 3 and the particle mean diameter was 0.589 mm (20/40 mesh sand).
  • the fluid modeled contains 3.6 kg/m 3 bromate-crosslinked guar.
  • the "low- viscosity” fluid modeled contains 3.6 kg/m 3 uncrosslinked guar and was assumed to have the same density and rheology as water. These were the high and low viscosity fluids used in each of the examples.
  • the first stage was a clean pad.
  • the second stage contained the barrier plug; the third and fourth stages were clean fluid.
  • Figure 7 shows the calculated results.
  • a barrier was placed in approximately the near- wellbore half of the fracture, primarily in the near-wellbore third of the fracture and almost all at the bottom. Not shown is that when a similar treatment was modeled except that all four stages used the high-viscosity fluid, the proppant was distributed throughout the fracture with the highest concentration centered (between the top and the bottom) about two thirds of the way to the tip.
  • the barrier particle distribution was in the shape of a horizontal "U" with the open end toward to wellbore; the viscous fluid following the barrier particle slug pushed the slug into the fracture but there was no low-viscosity fluid through which the particles could settle. Also not shown is that when a similar treatment was modeled except that the first stage was the low-viscosity fluid and the last three stages were the high viscosity fluid, a significant portion of the slug formed a barrier at the bottom of the fracture, and most likely, would bridge the lower fracture edge, but there was an upper wing of the deformed slug that had not settled and thus could mix with the conventional proppant in the treatment to follow.
  • the third stage was lower-viscosity fluid and the other three stages were higher- viscosity fluid, the performance was almost as good as the base case, although the barrier had a slightly lower particle concentration and was a little closer to the wellbore.
  • a lower-viscosity first stage was preferable, and additionally a lower- viscosity stage after barrier slug injection (to displace at least a larger part of the slug towards the bottom of the fracture according to the Saffman-Taylor instability mechanism and to promote barrier particle settling as shown in Figure 7 for the design of Table 1) was more preferable.
  • This lower-viscosity stage after the barrier slug injection is kept small to minimize the possibility of a screenout.
  • the next example illustrates the placement of a barrier stretched along the bottom edge of the fracture.
  • an auxiliary stage was introduced between pumping the barrier particle slug (Stage 2) and injecting the low- viscosity fluid (Stage 4 in this example).
  • Stage 3 a small portion of clean cross-linked gel was introduced.
  • Table 2 The extended job design is presented in Table 2.
  • the next example illustrates the effect of the rheology of the fluid injected before the slug on the final pattern inside the fracture.
  • the pad fluid used was a highly- viscous cross-linked gel.
  • two barriers were placed, one at the bottom and one at the top of the fracture.
  • the lower-viscosity fluid fingered into the higher-viscosity fluid according to the Saffman-Taylor instability and cut the barrier particle slug into uneven parts; the larger portion was displaced and then settled towards the bottom and the smaller portion was pushed towards the top.
  • the particles used in this simulation had a mean diameter equal to 0.661 mm and a density of 2540 kg/m 3 .
  • the results calculated for the particle concentration distribution are summarized in Figure 9, and the pumping schedule is presented in Table 3.
  • the flow rate was set to 3.2 m 3 /min, which is near the lowest pumping flow rate possible for most operators' equipment. (Lower flow rates are better and are permissible if the operator's equipment allows.)
  • the pumping schedule and the resulting particle concentration distributions are shown in Table 4 and Figure 10.
  • the concentration pattern shown in Figure 10 corresponds to a quite successful placement of a barrier stretched along the fracture, bridging a substantial portion of the lower fracture edge.
  • this pumping schedule was selected from a number of schedules tried. For example, not shown was a similar simulation in which the fifth stage was 30 instead of 100 m 3 ; more of the barrier material ended up at the top of the fracture and nearer the wellbore on the bottom. Also not shown is that when a treatment following the schedule of Table 4, but with the higher-viscosity fluid used in all stages, was modeled, the barrier was not placed in the bottom, but rather in the middle (vertically) of the fracture, and the fracture height was much greater, especially near the wellbore.
  • Modeling with any of a number of simulators available may be used by one skilled in the art to select a suitable job design for the nature of the strata to be treated and the desired end result and for the available equipment, fluids, and barrier materials.
  • Conventional fracture treatments are designed so that the velocity of longitudinal proppant transport away from the wellbore is much greater than the velocity of proppant settling (or rising).
  • Barrier placement treatment designs are intended to make these rates approximately comparable, and preferably to make settling (rising) take less time than longitudinal transport.

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Abstract

L'invention concerne un procédé destiné à créer, dans une formation souterraine, une fracture présentant une barrière à l'écoulement de fluides dans sa partie supérieure et / ou sa partie inférieure. Le procédé est appliqué avant ou pendant un traitement conventionnel de fracturation hydraulique et est utilisé pour limiter la croissance verticale indésirable d'une fracture hors de la zone productive. Un fluide tampon de viscosité inférieure est utilisé pour amorcer la fracture; un fluide de viscosité supérieure contenant des particules formant barrière est ensuite injecté; un fluide de viscosité inférieure exempt de particules est alors injecté pour favoriser le dépôt (ou l'élévation) des particules formant barrière et pour former une digitation à travers le bouchon de particules formant barrière et le dissocier en une partie supérieure et une partie inférieure. Si la barrière doit se trouver dans la partie inférieure de la fracture, les particules formant barrière sont plus denses que les fluides; si la barrière doit se trouver dans la partie supérieure de la fracture, les particules formant barrière sont moins denses que les fluides. Éventuellement, entre la phase de transport de la barrière et la phase subséquente de viscosité inférieure, on peut intercaler une phase faisant intervenir un fluide de viscosité supérieure exempt de particules qui enfonce davantage les particules formant barrière dans la fracture. Afin de mettre en place à la fois des particules supérieures et inférieures en un seul traitement, la phase tampon peut être de viscosité supérieure ou les particules formant barrière peuvent comprendre à la fois des particules moins denses et des particules plus denses que le fluide.
PCT/RU2008/000756 2008-12-10 2008-12-10 Régulation de la croissance en hauteur de fractures hydrauliques WO2010068128A1 (fr)

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US8797037B2 (en) 2008-04-11 2014-08-05 Baker Hughes Incorporated Apparatus and methods for providing information about one or more subterranean feature
US8841914B2 (en) 2008-04-11 2014-09-23 Baker Hughes Incorporated Electrolocation apparatus and methods for providing information about one or more subterranean feature
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
CN111396018A (zh) * 2020-05-15 2020-07-10 中国石油天然气集团有限公司 一种提高非均质储层支撑剂铺置效果的压裂方法
CN112431569A (zh) * 2020-10-15 2021-03-02 中国石油天然气股份有限公司 一种防止裂缝向上延伸的方法、高分子封堵材料及其制备方法
US11047220B2 (en) 2017-01-31 2021-06-29 Halliburton Energy Services, Inc. Real-time optimization of stimulation treatments for multistage fracture stimulation
CN115434659A (zh) * 2021-06-02 2022-12-06 中国石油天然气集团有限公司 高渗储层封堵剂深部定点投放的工艺方法

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US9850748B2 (en) * 2012-04-30 2017-12-26 Halliburton Energy Services, Inc. Propping complex fracture networks in tight formations
US9418184B2 (en) * 2013-07-25 2016-08-16 Halliburton Energy Services, Inc. Determining flow through a fracture junction in a complex fracture network
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US9909057B2 (en) 2013-09-20 2018-03-06 Halliburton Energy Services, Inc. Methods for etching fractures and microfractures in shale formations
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WO2017069760A1 (fr) * 2015-10-22 2017-04-27 Halliburton Energy Services, Inc. Amélioration de réseaux de fractures complexes à soutènement dans des formations souterraines
US11767745B2 (en) * 2016-09-29 2023-09-26 Schlumberger Technology Corporation Use of energetic events and fluids to fracture near wellbore regions
US20190040305A1 (en) * 2017-08-01 2019-02-07 Weatherford Technology Holdings, Llc Fracturing method using a low-viscosity fluid with low proppant settling rate
CN107699224B (zh) * 2017-10-10 2020-03-27 西南石油大学 一种控制水力压裂裂缝延伸上端高度的导向剂
US11566504B2 (en) 2019-07-17 2023-01-31 Weatherford Technology Holdings, Llc Application of elastic fluids in hydraulic fracturing implementing a physics-based analytical tool
US11981865B2 (en) 2019-10-18 2024-05-14 Schlumberger Technology Corporation In-situ composite polymeric structures for far-field diversion during hydraulic fracturing
CN112228031A (zh) * 2020-10-14 2021-01-15 中国石油天然气股份有限公司 一种控制裂缝延伸方向压裂方法

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US8797037B2 (en) 2008-04-11 2014-08-05 Baker Hughes Incorporated Apparatus and methods for providing information about one or more subterranean feature
US8841914B2 (en) 2008-04-11 2014-09-23 Baker Hughes Incorporated Electrolocation apparatus and methods for providing information about one or more subterranean feature
WO2012106017A3 (fr) * 2011-01-31 2012-10-18 Baker Hughes Incorporated Appareil et procédés pour suivre l'emplacement d'un fluide de fracturation dans une formation souterraine
CN103354858A (zh) * 2011-01-31 2013-10-16 贝克休斯公司 用于追踪地下岩层中的压裂液的位置的设备和方法
US11047220B2 (en) 2017-01-31 2021-06-29 Halliburton Energy Services, Inc. Real-time optimization of stimulation treatments for multistage fracture stimulation
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
CN111396018A (zh) * 2020-05-15 2020-07-10 中国石油天然气集团有限公司 一种提高非均质储层支撑剂铺置效果的压裂方法
CN112431569A (zh) * 2020-10-15 2021-03-02 中国石油天然气股份有限公司 一种防止裂缝向上延伸的方法、高分子封堵材料及其制备方法
CN112431569B (zh) * 2020-10-15 2022-12-02 中国石油天然气股份有限公司 一种防止裂缝向上延伸的方法、高分子封堵材料及其制备方法
CN115434659A (zh) * 2021-06-02 2022-12-06 中国石油天然气集团有限公司 高渗储层封堵剂深部定点投放的工艺方法
CN115434659B (zh) * 2021-06-02 2024-03-01 中国石油天然气集团有限公司 高渗储层封堵剂深部定点投放的工艺方法

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