MX2012013299A - Hydraulic fracturing method. - Google Patents

Abstract

A method is given for diverting injected slickwater in a hydraulic fracturing treatment. The diversion fluid is preferably a substantially proppant free viscous fluid that causes a net pressure increase and 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 method generates a greater fracture network complexity and thus a higher contact area with the reservoir during a single treatment cycle.

Description

HYDRAULIC FRACTURING METHOD BACKGROUND OF THE INVENTION The recovery of hydrocarbons from unconventional deposits, for example, strong sandstones and shales, usually requires stimulation, for example, hydraulic fracturing, to achieve economic production. Water or slurry (so called when water is used with a small amount of a friction reducer) is usually used as a fracturing fluid to stimulate unconventional low permeability deposits. These treatments are designed to stimulate large volumes of deposits and further open the surface area of rocks that retain hydrocarbons, thus boosting production. While slurry fluids generally provide inadequate transport for conventional proppant due to their very low viscosity, they are still considered efficient and economical. The use of low viscosity fluids for the stimulation of fractures in low permeability deposits sometimes results in the creation of a network of interrelated fractures and sometimes results in the propagation of a single flat fracture. Although the low conductivity achieved with these treatments is usually adequate in shale formations, it is believed that an increase in the contact area by creating a complex network of fractions is one of the key factors that can enhance the production of hydrocarbons in these formations.

The existing treatment techniques have not proven to be sufficiently effective for the formation of fracture networks with high fracture densities. The complexity of the fracture network is reflected in the number of interrelated fractures in the fracture network system as shown in Figure 1. There is a need for a reliable technique for the treatment of fractures that generates greater complexity in the fracture network. network of fractures and therefore a greater area of contact with the deposit during a single treatment cycle.

BRIEF DESCRIPTION OF THE INVENTION One embodiment of the invention is a method for fracturing an underground formation where a sequence of fluids is injected into the formation; the sequence has as a feature a first cycle involving (a) injecting a fluid pad having a viscosity of less than about 50 mPa-s at a cutting speed of 100 s "1 under ambient conditions, (b) injecting a solution proppant having a viscosity of less than about 50 mPa-s at a cutting speed of 100 s "1 under ambient conditions, (c) injecting a thick fluid (which will act as a deviating agent) having a viscosity greater than about of 50 mPa'S at a cutting speed of 100 s-1 under ambient conditions, and one or more subsequent cycles that incorporate the repetition of steps (b) and (c). Optionally, a fluid pad is injected first. Typically the permeability of the formation is less than about 1 mD.

In another embodiment, the thick bypass fluid has a viscosity of less than about 20 mPa-s when pumped and then thickened in the reservoir, for example, the reservoir contains carbonate and the thick fluid is initially acidic and becomes more viscous as the acid is consumed. Autonomous bypass acid systems can be used to form such systems that thicken in the tank.

In several embodiments, the thick fluid also 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 that is selected, for example, from spheres, rods, cylinders, plates, sheets, spherical cylinders, ellipsoids, toroids, elongated figures, fibers, arcs / cells, meshes, meshes / cells, honeycombs, bubbles, type structures sponge or foam type, and mixtures of these forms; The proppant size varies between about 5 and about 1000 microns.

In yet another embodiment, at least one of the injected fluids comprises degradable solid materials, for example, polylactic acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic acid with other hydroxycarboxylic acids or residues containing hydroxycarboxylic acid , copolymers of lactic acid with other hydroxy carboxylic acids or residues containing hydroxycarboxylic acid and mixtures of these materials. Degradable materials are typically used in the form of fibers, plates, chips, beads and combinations thereof.

In additional embodiments, the fluid from step (a) or the fluid from step (b) or both, contain a friction reducing agent. The fluids of step (c) may optionally contain less than about 0.024 kg proppant per liter of clean fluid or optionally may be substantially proppant free.

In still further embodiments, one or more cycles are followed by an injection of a fluid having a viscosity greater than about 50 mPa · s at a cutting speed of 100 s "1 under ambient conditions and containing a thick proppant; the injection steps of a fluid have a viscosity greater than about 50 mPa · s at a cutting speed of 100 s "1 under ambient conditions containing a thick proppant optionally followed by an injection of a fluid containing a control agent of proppant recovery.

In another embodiment, the method includes a final step of injecting a flushing fluid; at least one of the fluids is viscosified with a degradable viscosifying agent. In other embodiments, at least one step (b) after the first step (b) is preceded by one step (a) or each step (b) is preceded by one step (a).

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. In each cycle the ratio between the volume of fluid in stage C and the volume of fluid in stage B is preferably less than about 1/10.

BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 illustrates the complexity of the fracture system, which increases from A to B to C.

Figure 2 is a schematic diagram of the collector system.

Figure 3 shows the pressure in the collector system compared to time.

DETAILED DESCRIPTION OF THE INVENTION The invention is described in terms of vertical well treatment, but is applicable in the same way to wells of any orientation. The invention will be described for hydrocarbon production wells, but it should be understood that the invention can be used for wells for the production of other fluids, such as water or carbon dioxide or, for example, for injection or storage wells. It should further be understood that, throughout the present specification, when a range of concentration or amount is described as useful, suitable or the like, it is intended that any and all concentrations or amounts within the range, including the criteria of valuation, should be considered as established in the report. Also, each numerical value should be understood once as modified by the term "around" (unless it has already been expressed as modified) and then it should be understood again as not being modified, unless otherwise expressed in the context. For example, "a range of 1 to 10" should be understood as indicating all and any possible numbers comprised between about 1 and about 10. In other words, when a given interval is expressed, even if only they are identified or mentioned explicitly a few specific data within the range, or even if no data is mentioned within the range, it should be understood that the inventors recognize and understand that all and any data within the range should be considered explicit, and that the inventors possess all of the interval and all the data within the interval.

We have developed a method to increase the complexity of the fracture system to enhance the production of hydrocarbons in unconventional low permeability deposits. In the method, a sequence of stages is pumped into the reservoir; a low viscosity fluid treatment is complemented by at least one pumping step of a relatively low volume of a fluid, viscosified by a degradable viscosifying agent that is used as a bypass agent. The pumping of the viscous fluid deflection agent leads to an increase in net pressure and to the plugging of some microfractures in the initially created fracture system, which includes the formation of complementary microfractures connected to the initial fracture network and increases the area of fractures. contact with the rock formation. The viscous screen injection of the deviating agent is generally repeated. Said use of viscous fluid screens allows the stimulation of larger deposit volumes in remote regions of a deposit. After treatment, the viscosified fluid is naturally degraded or destroyed with a crusher, opening production from temporarily clogged fractures. Note that the present invention relates to a method for redirecting the treatment within an already stimulated zone that results in the creation of a greater contact area with the reservoir because the fracture complexity increases within that zone.

When multiple productive zones are stimulated by fractures, it is usually necessary to treat multiple zones in multiple stages. This creates the need for a deviation technique that allows to redirect the treatment between zone and zone. Said deviation, optionally with new perforations thrown after each treatment, is performed, for example, with bridge plugs, ball-type sealants, solid gel plugs or fiber plugs, powder, flakes, granules, pellets and degradable pieces, optionally with coatings which dissolve slowly in water. The other situation in which a deviation is required is the redirection of the treatment within a stimulation zone. In this case, an additional rock formation volume is stimulated using the same entry point in the formation without redirecting the treatment to another area through the well. It is interesting to know that the techniques have been developed using viscous fluid screens or fine sand for the control of leaks and to reduce and not increase the complexity of the fracture in naturally fractured deposits. The creation of a single flat fracture in the area near the well instead of multiple interrelated fracture channels has been considered in the past that deliberately seeks to provide a significant reduction in tortuosity and minimize the risk of premature elimination.

Slurry treatments have been shown to provide comparable production to conventional gel treatments, but at a significantly lower cost. One of the most important features of grout work is the little damage to the gel, due to the low polymer content of the fluid. However, the low viscosity of the fluid strongly affects its proppant transport properties and the placement of the proppant well inside a fracture is a challenge. The use of ultralight and lightweight proppant is a solution. Another solution is to pump a combination of slurry and gel in stages with varying amounts of proppant; such treatments are usually called hybrid fractures or hybrid hydraulic fractures. Although the objective of hybrid fractures is a better placement of the proppant with a fluid of higher viscosity than that of the grout, other benefits can be observed that include the creation of wider fractures and therefore avoid the bridging of proppers. It has also been observed that hybrid fractures can generate higher effective fracture lengths, but the effective conductivities in hybrid fractures were not systematically greater than those in hydraulic fractures.

Grout fractures have been tested without proppant or only with thick proppant or with alternations of these two. However, the normal grout treatment includes the following steps: a) grout pad; b) slurry stage with fine proppant (for example sand of approximately 100 mesh (grains of between about 0.105 and about 0.21 mm) or around sand 30/70 (between about 0.21 and about 0.595 mm)) in concentrations that grow gradually between about 0.1 and about 2 ppa (pounds of proppant added) (between about 0.012 and about 0.240 kg of aggregate sand per liter of clean fluid); c) linear gel (with a typical viscosity between about 10 and about 100 mPa · s at a cutting speed of 100 s "1) with thick proppant (for example about 20/40 sand (between about 0.42 and about 0.841 mm) or around sand coated with 20/40 resin) in concentrations that increase up to around 5 ppa (about 0.6 kg of aggregate sand per liter of clean fluid) to leave the nearby well region of the fracture open; ) rinse Typically, the pad stage is between about 500 and about 3000 bbl (between about 80 and about 480 m3), the grout stage is between about 500 and about 25,000 bbl (between about of 80 and about 4000 m3), the gel stage is between about 500 and about 25,000 bbl (between about 80 and about 4000 m3) and the rinse is approximately the volume of the well from the mouth of the well to the perforations, sometimes up to about 50 bbl (around 8 m3).

Hybrid treatments aim to achieve the benefits of conventional gel and grout treatments. Typically, hybrid fractions include pumping of: a) slurry pad; b) an optional stage of grout with fine proppant (for example less than about 0.5 ppa (about 0.06 kg / 1 of clean fluid)); c) cross-linked gel with a viscosity of between about 100 and about 1000 mPa · s at a cutting speed of 100 s_1 with thick proppant, for example about 20/40 (between about 0.4 and about 0.841 mm), ( at a concentration of for example up to about 5 ppa (about 0.6 kg of sand added per liter of clean fluid)); optionally repeating steps b) and e); and rinse. The volumes are typically similar to those of conventional slurry treatments as described above. In a modification of the hybrid fracture called inverse hybrid fracture, the fluid injection sequence is changed, so that a high viscosity polymer (linear or crosslinked) is used to create a fracture, while the proppant is transported with a low viscosity fluid it is pumped behind the viscous pad. The viscosity contrast results in the formation of fingers of fluid loaded with low viscosity proppant in the higher viscosity fluid and the proppant deposit is impeded by the layers (fingers) of the more viscous fluid.

Again, as in classic hybrid fractures, the design objective is to administer the proppant well inside the fracture to ensure greater length and higher fracture conductivity. In any slurry pumping program, when the fluid changes from slurry to viscous proppant suspension, the fluid can be changed from slurry to viscous fluid for a period of time before the proppant is added; for example, in another version of a hybrid fracture, the grout is pumped first to generate length; This is followed by a reticulated gel pad and then coarse sand in a cross-linked gel.

The key distinction of the method of the present invention from hybrid fractures is in the volumes of the viscosified fluids pumped in the slurry stages. Since the proppant placement is not the actual objective of the method of the invention, the viscous fluid is only a small fraction of the total work volume. In addition, the concentration of proppant in the viscosified fluid is similar to that in the slurry stages.

Unconventional gas deposits are characterized by permeabilities of extremely low formations (eg less than about 0.1 mD to about 100 nD in shales), and stimulation treatments usually require large volumes of treatment (eg, greater than about 15,000 m3 (1 gal)) and high pumping rates (as examples, at least about 6.4 mVmin (40 bpm), typically around 10 m3 / min (60 bpm), and sometimes up to about 20 m3 / min (120 bpm)) to open large fractures and generate complex fracture networks that can provide an unlimited gas flow to a well. Fractures are typically shored with sands of various sizes transported by slurry fluids, which are usually water with small amounts of polymeric friction reducers having viscosities of up to about 50 mPa * s at a cutting speed of 100 s "1 Fluids having higher viscosities, for example, above about 15 cP are typically referred to as hydraulic fracture fluids: lightweight proppant, which have for example specific gravities of between about 2.2 and about 2.8 and ultralight props, which they have for example specific gravities of between about 1.0 and about 2.0 can be used for hydraulic fractures.Lubrication fluids contain considerably lower polymer concentrations than crosslinked or linear gels, so they damage the proppant package much less.

Various diversion techniques are used to increase the effective stimulated volume (ESV) of a reservoir. The methods depend on the temporary filling of some areas (for example areas already stimulated) to stimulate others with the same treatment. Most of the existing diversion methods are directed to wells and boreholes to stimulate different formation zones. These methods include various zone transmission isolation tools by coating, such as bridge plugs, sand plugs, ball-type sealants, induced stress shunting and others. Deviation within a fracture is less common in the technique of hydraulic fracturing. One method provides a deviation of fracture near the well on demand. The method uses a mixture of proppant and degradable fiber and a placement strategy to temporarily cover one side of the fracture in the region near the well to allow diversion of treatment to a different well zone.

The present invention describes a method for increasing the complexity of the fracture network and enhancing the contact area with the reservoir by means of viscosified fluids. The viscosified fluids can be selected from fluids such as, but not limited to, viscoelastic surfactants, borate and / or metal crosslinked polysaccharides, for example, guar gums, cellulose derivatives, xanthanes, scleroglucans, etc. The fluids may additionally include crosslinking retarding agents to control fluid viscosity, crushers, including encapsulated crushers, to ensure degradation of the screen after treatment, degradable fibers and other additives. Said fluids and their components are known to those skilled in the art. The method is preferably applied to formations having a permeability of less than about 1 mD, more preferably to formations having a permeability of less than about 10 mD, and more preferably to shale formations with permeabilities of less than 1000 nD. The method can be used in a refractive treatment.

As in the common slurry treatment, a typical treatment of the invention begins with a pad, stage A, in which a pure slurry fluid is pumped. The pad stage creates the fracture system and ensures that the width is sufficient for the passage of the proppant. The pad stage is followed by a large volume stage b, the pumping of a grout loaded with proppant that carries the proppant to the open 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 cutting speed of 100 s_1 at ambient conditions, preferably between about 1 and about 10 mPa-s at a cutting speed of 100 s. -1. The fluids A and B may be the same or different. Bracing for grout treatments are known to those skilled in the art; Non-exhaustive examples include sands and other rocks and minerals, which include Muscovite mica, ceramics, polymeric materials, biomaterials and mixtures of these materials. Special attention should be paid to the choice of proppant material, since the grouts have poor transport properties due to their very low viscosities. A deflection stage C follows the placement in the far field of the proppant in stage B and involves pumping a viscosified fluid, which optionally may contain proppant and / or fiber material / s. The fluid in step C has a viscosity, after viscosity, greater than about 50 mPa-s, preferably between about 100 and about 1000 mPa-s, at a cutting speed of 100 s-1 under ambient conditions. Optionally, the fluid from step C can 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 cutting speed of 100 s "1 (with a preferred range of between about 20 and about 100 mPa-s at a cutting speed of 100 s. ~) and the final viscosity is greater than about 50 mPa-s, preferably between about 100 and about 1000 mPa * s, at a cutting speed of 100 s "1 under ambient conditions. The volume of stage C is generally smaller than the volumes of the other stages of treatment. The ratio between the fluid volumes in stage C and the fluid in stage B is less than about 1/10, preferably between about 1/100 and about 1/10. The upper limit of the total volume of fluid in stage C of each treatment cycle (before redirecting the treatment to another well interval) is around 64 m3 (400 bbl); You can use as little as about 10 m3 of fluid. Fluid C optionally contains a fiber, for example, a degradable fiber and / or a proppant. The preferred proppant size is between about 0.05 mm and about 1 mm (preferably between about 0.2 and about 0.4 mm, the preferred proppant concentration is between about 0.012 and about 0.6 kg added per liter of clean fluid ( more preferably between about 0.024 and about 0.24 kg per liter of clean fluid).

A particularly suitable method for pumping a Stage C low viscosity fluid and then increasing the viscosity of the fluid in the carbonate-containing reservoir, for example a carbonate-containing shale, is the use of an acidic fluid which is subjected to an increase in the viscosity when the pH is increased, for example, by contact with the deposit rock. Many of these systems are known for their use in acidification and acid fracturing; they are commonly referred to as autonomous deviating acids and when based on viscoelastic surfactants they are referred to as viscoelastic deviation acids. In the present invention, they are used to deflect grout. Examples are those based on viscoelastic surfactants, for example certain betaines. Some viscosifiers and systems are described in the US patents. No. 6, 399,546; 6,667,280; 6,903,054; 7,119,050; 7,148,184; 7,380,602; and 7,666,821. In addition to the deviation, the use of said autonomous detouring acids in the present invention can further enhance the complexity of the fracture networks by introducing heterogeneity by recording the formation and reducing the fracture initiation pressure and also by the selective dissolution of the fracture. crust, which normally have accumulated in the fractures / fissures / natural structures of a deposit.

Stage C may also contain fibers, which preferably have a diameter of between about 1 and about 100 microns (more preferably between about 10 and about 30 microns) and a length between about 1 and about 50 mra ( preferably between about 3 and about 35 MI) at a concentration between about 0 and about 60 g per liter of clean fluid, (preferably between about 1.2 and about 16 g per liter of clean fluid).

The substantially proppant free fluid is defined herein as a fluid having a proppant load of less than about 0.024 kg per liter of clean fluid. A viscous fluid is intended and is therefore designed to deflect and not carry proppant or fiber. The fluids of stage C are substantially free of proppant.

The pumping of viscosified fluid increases the net pressure in the fracture, which temporarily reduces the flow of fluid in a portion of the primary fracture and induces the formation of secondary fractures along the primary fracture. This temporary increase in pressure can also reversibly increase the width of the fracture, reducing the likelihood of bridging the proppant in the fracture. Since the viscosified fluid has a density close to that of the slurry, the fluid screens can be transported to a network of fracture networks and no problems are associated with the deposit of the screen (see Example 1).

The fluids A and B are preferably selected from fresh water, brine, sea water, polymer solutions, viscoelastic surfactant solutions, gelled oils, diesel-type diesel fuels, emulsions and mixtures of said fluids. The fluid C is preferably chosen from solutions of polymers, gels, crosslinked gels, viscoelastic surfactant solutions, gelled oils, viscosified diesel fuels and emulsions. These viscosifiers are preferably degradable. Preferred polymers include guar gum, gum arabic, karaya gum, tamarind gum, locust bean gum, cellulose, xanthan, scleroglucan, polyacrylamide, polycarboxy, combinations of these materials, and modified, substituted or derived versions of these polymers. The polymers in the fluids can be crosslinked, for example, by compounds of boron, aluminum, titanium, zirconium, chromium, iron, copper, zinc, antinomy, organic or inorganic pollons and combinations of these materials. Fluids may optionally contain crosslinking delaying agents or gel or polymer shredders, for example, encapsulated gel shredders, internal retardation gel shredders, temperature activated gel shredders and combinations thereof. The proppant in fluid B and optionally in fluid C, is preferably selected from sand, ceramics, glasses, rocks and minerals such as mica, organic and inorganic polymers, metals and alloys, composite materials and mixtures of these materials. These proppants preferably have shapes that are selected from spheres, rods, cylinders, plates, sheets, spherocylinders, ellipsoids, toroids, elongated figures, fibers, meshes, arcs / cells, meshes / cells, honeycombs, bubbles, sponge-like or foam-like structures. , and mixtures of these forms. "Arcs / cells" and "meshes / cells" are special three-dimensional organizations of materials, for example cross-linked foamed polyurethane. These materials have a three-dimensional bubble structure consisting of, for example, dodecahedron, each face of this is a pentagon. Pentagons are formed with edges between which there is a membrane or window. At least one membrane is always missing, therefore an open pore structure is formed. The vicosifiers and proppants and methods for preparing these fluids are known in the art.

The proppant in the fluids B and optionally C, preferably is in a range of sizes between about 5 and about 1000 microns, more preferably between about 50 and about 840 microns. These proppant may optionally be coated or may have an organophilic treatment. Fluid B preferably carries at least about 90 weight percent proppant in steps B and C.

The fluids of steps B and C may also optionally 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 hydroxycarboxylic acids or residues containing hydroxycarboxylic acid, copolymers of lactic acid with other hydroxy acids. carboxylic or residues containing hydroxycarboxylic acid and mixtures of these materials.

Any of these fluids, in particular, the fluids used in stages C, can be foamed or activated.

It is generally believed that fracture systems formed with hydraulic fractures in heterogeneous deposits have complex and branched structures with many interrelated natural fractures, with changes in the direction of the fractures (see Figure 1C). However, the viscosified fluids and methods used in the present invention plug existing fractures at a considerable distance from the well; this depends on the viscosity of the fluid which in turn can be controlled by a delay agent. By modifying the delay time, an operator can control the distance from the well in which the shutter occurs. The plug formed drastically increases the pressure and induces the creation of new fractures connected to the same network of fractures, which grows in other directions, stimulating the areas not previously treated (see Example 2).

Stages A (optionally) and B are repeated after each deviation (stage C) to create new fractures and fracture networks. Each pumping of at least one stage B and stage C (in any order) is called a cycle; each cycle contains at least stages B and C; the entire treatment begins with a stage A. 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 desired fracture network. The ratio between the volumes, in any cycle, of fluid in stage C and the fluid in stage B is less than about 1/10, preferably between about 1/100 and about 1/10. The upper limit of the total volume of fluid in stage C of each treatment cycle (before redirecting the treatment to another well interval) is around 64 m3 (400 bbl); You can use as little as about 10 m3 of fluid. Any cycle may optionally include a stage A and optionally a stage D may follow, where a gel with thick proppant (for example between about 0.4 and about 1 mm (preferably between about 0.42 and about 0.84 mm)) is pumped. to prop up the primary fracture and make sure it has a high conductivity. At any stage D is optionally followed by a stage E, pumping a proppant recovery control agent, by e. , proppant coated with resin or any other proppant control agent known in the art, such as fibers, and finally with an optional rinse, stage F. Water, brine or a fluid that is the same or similar to the fluid of any stage A can use for rinsing; the rinse is usually around the volume of the well from the mouth of the well to the top or bottom of the perforated interval being treated (increase or reduction between about 3 and about 100 bbl (between about 18 and about 65 m3) The fluid of any stage D has a viscosity of between about 1 and about 1000 mPa * s at a cutting speed of 100 s "1, the fluid in any stage E has a viscosity of between about 1 and around 50 mPa-s at a cutting speed of 100 s 1.

The fluid from each stage A, stage B, stage C, stage D, or stage E does not have to be identical to the fluid from any other stage A, stage B, stage C, stage D, or stage E. After the end of the treatment and the closure of the fracture, the fluid plugs created by the stages C for the deviation are naturally degraded or destroyed with oxidative or other types of crushers, which reduce the viscosity of the fluid. This opens the originally fractured regions of the deposit and provides transport of hydrocarbons or other fluids to the well, boosting production.

The examples illustrated below illustrate the transportability of a fluid viscosified in a slurry fluid having a similar density (Example 1); sealing a collecting system (simulating a complex network of fractures) with a viscosified fluid screen (Example 2); and degradation of the plug over time in the presence of an oxidative shredder (Example 3). The examples are presented for the purpose of illustrating the preferred embodiments of the invention and do not constitute any limitation to the scope of the invention.

Example 1: A fluid screen prepared from a guar gel cross-linked with borate, having a guar concentration of 6 g / L (50 lb / 1000 gal) was placed in a Plexiglas reservoir groove of dimensions 1000 x 300 x 4 mm, above a slurry screen of similar density containing 0.05 weight percent of a polyacrylamide friction reducer. No screen diffusion was observed during the experimental time of 4 hours at room temperature. The viscous screen remained consolidated and floated to the grout screen without depositing.

Example 2: The behavior of a viscous screen that is transported in a horizontal tube was studied. A laminar fluid flow regime was tested. These data can be used to evaluate the transport of screens within a fracture. In order to investigate the dependencies of the transport of screens, a special installation was built. It consists of a transparent plastic water tube (35 m long and 18 mm ID), systems for the injection of the viscous screen and a base fluid, a water pump, and two photosensors (one at the beginning and one at the end of the tube) to determine the length of the viscous screen and a data acquisition system. A special loop for the injection of viscous fluid screens was used. A viscous screen of a desired composition was loaded into the screen injection loop before the experiment and isolated from the main line by valves. The base fluid was pumped through the tube for several minutes until the base fluid flow was stabilized. Once the flow stabilization was achieved, it was directed to the screen sample injection loop and a viscous screen was pumped into the system.

Viscous fluid screens were prepared from a guar gel cross-linked with borate having a guar concentration of 6 g / L (50 lb / 1000 gal) and stained with phenolphthalein for visualization; a base fluid, slurry, containing 0.05% by weight of a polyacrylamide friction reducer was used. The viscous fluid and slurry screens were pumped and the dilation of the screen during transport in the tube was studied. The flow rate of the slurry was 8.1 L / min, which corresponds to a linear velocity of 43.6 cm / sec. The experiment showed that the average viscous fluid screen speeds were 42 cm / sec. The difference between the velocities of the base fluid and the viscous screen was caused by a fingering effect where the denser and more viscous fluid was transported at a lower speed in relation to the base fluid velocity. The initial injected sieve lengths were 215 + 20 cm. The final sieve lengths at the end of the tube were 250 ± 24 cm. No significant screen dilation was observed during transport within the tube when the flow was laminar. These experiments show that it is possible to transport viscous fluid screens within a fracture; The screens did not disperse significantly under conditions that simulate flow conditions within a fracture.

Example 3: A manifold [3] as shown in Figure 2 was constructed using Swagelok tubes with outside diameters ranging from 6.35 mm (0.25 in) to 1.59 mm (1/16 in). Figure 3 shows the results of tests where the pressure inside the tube is plotted against time. The same slurry used in Examples 1 and 2 was pumped through the manifold with a Knauer pump [1] at 0.5 1 / min flow rate with pressures that generally do not exceed 138 kPa (20 psi). The cross-linked gel screens used in Examples 1 and 2 were then placed in the suspension tank [2] and the pressure was followed during pumping; the pressure increased to 1007 kPa (146 psi), and at that pressure the rupture disc of pressure release [4] broke. The collector system emulates a complex network of fractures during the detour stage, and the rupture disk breaks the simulated fracture of an unstimulated zone of the deposit due to the pressure increase ne

Claims (15)

CLAIMS Having now described our invention, the following is claimed:

1. A method for fracturing an underground formation comprising a first cycle comprising (a) injecting a fluid pad having a viscosity of less than about 50 mPa-s at a cutting speed of 100 s_1 at ambient conditions, (b) injecting a proppant solution having a viscosity less than about 50 mPa · s at a cutting speed of 100 s-1 at ambient conditions, (c) injecting a thick fluid having a viscosity greater than about 50 mPa-s at a rate cutting 100 s "1 under ambient conditions, and one or more subsequent cycles comprising the repetition of steps (b) and (c).

2. The method of claim 1 or 2, wherein the thick fluid has a viscosity of less than about 20 mPa-s when it is pumped and then thickened.

3. The method of claim 2, wherein the deposit contains carbonate and the thick fluid is initially acidic and / or the permeability of the formation is less than about 1 mD.

. The method of any of the preceding claims, wherein the thick fluid additionally comprises a proppant.

5. The method of any of the preceding claims, wherein the total volume of fluid injected in steps (b) comprises at least 75 percent of the total volume of fluid injected in the treatment.

6. The method of any of the preceding claims, wherein at least one of the injected fluids comprises degradable solid materials which are selected from the group consisting of polylactic acid, polyglycolic acid, polylactic acid and polyglycolic acid copolymers, copolymers of glycolic acid with other acids hydroxycarboxylics or moieties containing hydroxycarboxylic acid, copolymers of lactic acid with other hydroxycarboxylic acids or moieties containing hydroxycarboxylic acid and mixtures thereof.

7. The method of claim 11, wherein the degradable materials are used in the form of fibers, plates, flakes, beads and combinations thereof.

8. The method of claim 1, wherein the fluid of step (a) or the fluid of step (b) or both, comprises a friction reducing agent.

9. The method of claim 1, wherein the fluid of step (s) (c) comprises less than about 0.024 kg proppant per liter of clean fluid.

10. The method of claim 1, wherein one or more cycles are followed by an injection of a fluid having a viscosity greater than about 50 mPa * s at a cutting speed of 100 s "1 under ambient conditions and comprising a coarse proppant.

11. The method of claim 1, comprising a final step of injecting a flushing fluid.

12. The method of claim 1, wherein at least one step (b) after the first step (b). it precedes you one step (to) .

13. The method of claim 1, wherein at each step (b) a step (a) precedes it.

14. The method of claim 1, wherein the total volume of the fluid injected in step (c) comprises less than 10 percent of the total volume of fluid injected in the treatment.

15. The method of claim 1, wherein in each cycle the ratio between the volume of fluid in stage C and the volume of fluid in stage B is less than about 1/10.