MX2014004338A - Hydraulic fracturing with proppant pulsing through clustered abrasive perforations. - Google Patents

Abstract

Well completion techniques are disclosed that combine the creation of perforation clusters created using abrasive-jet perforation techniques with hydraulic fracturing techniques that include proppant pulsing through the clustered abrasive jet perforations. Both the abrasive-jet perforation and hydraulic fracturing with proppant pulsing may be carried out through coiled tubing.

Description

FRACTU HYDRAULIC FIXING WITH EMISSION OF AGENT IMPULSES STRENGTH THROUGH ABRASIVE PERFORATIONS CONGLOMERATES Background Hydrocarbons (petroleum, natural gas, etc.) are obtained from an underground geological formation by drilling a well that penetrates the formation containing hydrocarbons. This provides a partial flow path for the hydrocarbon to reach the surface. In order for the hydrocarbon to be "produced", that is, to move from the formation to the drilling well and finally to the surface, there must be a flow path sufficiently free of obstacles.

Hydraulic fracturing is a primary tool to improve well productivity by placing or extending highly conductive fractures from the wellbore into the reservoir. During the first phase, hydraulic fracturing fluid is injected through the drilling well into an underground formation with high flow and pressure. The injection rate of the fracturing fluid exceeds the filtration rate inside the formation producing an increasing hydraulic pressure at the physical interface between formation and well. When the pressure exceeds a critical value, the formation or rock strata crack and fracture. The formation fracture is more permeable than the formation porosity.

During the next phase, the shoring agent is deposited on the fracture to prevent it from closing a the injection is cut off. The resulting propped fracture enables an improved flow of recoverable fluid, ie oil gas or water. Many other shoring agents can be used such as sand, gravel, glass beads, nutshells, ceramic particles, sintered bauxites and other materials including spherical ball bearings, cylindrical or irregular.

Hydraulic fracturing fluids are aqueous solutions containing a thickener, such as a soluble polysaccharide, to provide sufficient viscosity to transport the binder. Typical thickeners are polymers, such as guar (phylogen polysaccharide), and guar derivatives (hydropropyl guar, carboxymethylhydropropyl guar). Other polymers can also be used as thickeners. The water with guar represents a linear gel with a viscosity that increases with the polymer concentration. Crosslinking agents are used which provide a contact between polymer chains to form sufficiently strong couplings that increase the gel viscosity and create visco-elasticity. Common crosslinking agents for guar include chemical compounds of boron, titanium, zirconium and charged with aluminum.

Fibers can be used to enhance the ability of the fracturing fluids to carry shoring agent and to mitigate the settling of shoring agent within the hydraulic fracture. For operations in which the shoring agent is pumped into plugs or pulses, fibers may also be used to mitigate the dispersion of shoring agent plugs as they move through the entire well termination and into the interior of the fracture.

Shoring agent return flow control agents may also be used during the later phases of the hydraulic fracturing treatment to limit the return flow of the shoring agent placed in the formation. For example, the shoring agent may be coated with a hardenable resin that is activated at the bottomhole conditions. Different materials, such as fiber bundles, or fibrous or deformable materials, have also been used to retain binder agents in the fracture. It can be assumed that the fibers form a three dimensional network in the shoring agent packaging that limits its return flow.

The success of a hydraulic fracturing treatment depends on the hydraulic fracture conductivity and the length of the fracture. The conductivity of the fracture is the product of the permeability of the bracing agent and the width of the fracture; the units are usually expressed as milidarcy-foot. The conductivity of the fracture is affected by a number of known parameters. The particle size distribution of the bracing agent is a key parameter that influences the permeability of the fracture. Another is the concentration of shoring agent between fracture interfaces (expressed in pounds of shoring agent per square foot of fracture surface) and influences the width of the fracture. High-strength shoring agents can be considered, fluids with excellent shoring agent transport characteristics (ability to minimize decanting driven by gravity within the fracture itself), high shoring agent concentrations, or large shoring agents as media to improve the conductivity of the fracture. Weak materials, poor transport of shoring agent, and narrow fractures all lead to poor well productivity. Relatively inexpensive materials of low strength, such as sand, are used for the hydraulic fracturing of formations with small internal stresses. Higher cost materials, such as ceramics, bauxites and others, are used in formations with small to moderate closing tensions. Higher cost materials are used, such as ceramics, bauxites and others, in formations with higher closing tensions.

The shoring agent packaging must create a conduit that has a higher hydraulic conductivity than the surrounding formation rock. The shoring agent packaging within the fracture is often modeled as a porous permeable structure, and the flow of formation fluids through this layer is generally described using the well-known Darcy's law (1) or the equation of Forscheimer (2): (1) < 9P / dx = - (Mu / k); (2) 3P3x = - [(Mu / k) + ppu2], in which P is the fluid pressure in the fracture; x is the distance along the fracture with respect to the drill hole; μ is the viscosity of the formation fluid; u is the flow rate (filtration) of the formation fluid; k is the permeability of the shoring agent packaging; ß is a coefficient referred to as a beta factor that describes nonlinear corrections to Darcy's filtration law; Y p is the density of the formation fluid.

Reference is made to the result of multiplying the permeability of the fracture by the width of the fracture as "hydraulic conductivity". The most important aspect of fracture design is the optimization of hydraulic conductivity for particular training conditions.

A fracture optimization process will strike a balance between the strength of the shoring agent, the hydraulic fracture conductivity, the shoring agent distribution, the cost of the materials, and the cost of executing a hydraulic fracturing treatment in a specific reservoir . The case of large shoring agent particle sizes illustrates the average term search performed during an optimization process. A significant hydraulic fracture conductivity increase is possible using large diameter shoring agents. However, at a given internal formation stress, large diameter shoring agents are crushed to a greater extent when subjected to high fracture closure stresses, which leads to a decrease in the effective hydraulic conductivity of the agent package. of shoring. In addition, the larger the shoring agent particles, the more these will be subject to the formation of seals and entrapment in the fracture near the injection site.

US 6,776,235, "Hydraulic Fracturing Method", which is hereby incorporated by reference, discloses a method and means for optimizing fracture conductivity. Well productivity is increased by sequentially injecting alternating phases of fracturing fluids into the drill hole, which have a contrast in their ability to transport propping agents to improve the placement of bracing agent, or have a contrast in the amount of propping agents transported. The bracing fractures obtained following this process have a pattern characterized by a series of bracing agent bundles scattered along the fracture. In other words, the bundles form "columns" that keep the fracture open along its length but that provide a lot of channels for the formation fluids to circulate.

Hydroabrasive methods for cutting and surface treatment are often used to cut grooves or drilling holes in casing and forming pipes instead of using explosive cumulative loads or mechanical burrs.

Devices for cutting grooves in a formation with a hydroabrasive jet can include a perforating device hung from a pipe inside a well with a hydroabrasive jet generator located on the surface of the soil. The drilling device may include two nozzles of opposite lateral orientation directed towards the wall of the well. A hydroabrasive slurry can be prepared in a hydroabrasive jet generator and pumped through the pipeline and to the bottom of the well to the drilling device. Other abrasive drilling devices are known in the art.

Summary of the Disclosure The present summary is provided to introduce a selection of concepts that are further described hereinafter in the detailed description. It is not intended that the present summary identify the key or essential characteristics of the subject matter claimed, nor is it intended that the present summary be used as an aid to limiting the scope of the subject matter claimed.

For the purposes of the present disclosure, the terms piercing and stationing are interchangeable and the term piercing will be used. On the other hand, a conglomerate may include one or more perforations. If the conglomerate includes a plurality of perforations, the perforations are grouped relatively close to one another and are usually formed simultaneously using an abrasive jet perforating tool with a plurality of nozzles. A plurality of conglomerates would refer to individual conglomerates (ie, one or more perforations) separated by a non-perforated interval.

In one aspect, a method for drilling and fracturing an underground formation with a drilling well lined with a casing extending through at least part of the formation. The disclosed method may include forming at least one drilling or drilling conglomerate through the casing and into the formation with hydroabrasive jets. The disclosed method can further include injecting a fracturing fluid free of binder into the drill hole through the conglomerate. The method disclosed may also include combining the fracturing fluid free of shoring agent with a shoring agent to form a first slurry loaded with shoring agent and injecting, alternatively and repeatedly, the first slurry loaded with shoring agent , and then inject the free fracturing fluid of the shoring agent into the drilling well and through the drilling conglomerate. The method may also include repeating the combination of the fracturing fluid free of the binder with the binder to provide extra binder-loaded slurries (ie, second, third, fourth, etc.) of agent concentrations. shoring variables, inject, so alternative and repeated, each slurry loaded with additional shoring agent, and subsequently inject the fracturing fluid free of shoring agent into the drilling well and through the drilling conglomerate. The method may also include forming a conglomerate or additional conglomerathrough the casing and into the formation with hydroabrasive jets, in which the conglomerate or additional conglomeraare separated from the other conglomerate or conglomeraby a non-perforated interval. . The disclosed method may also include treating all the conglomerasimultaneously with the fracturing fluid free of binder, and subsequently the binder loaded with binder as discussed above.

Brief Description of the Drawings Figure 1 illustraa plurality of discrete drilling conglomeraseparated by non-perforated intervals that can be formed by abrasive jet drilling.

Figure 2 illustraan annular fracturing tool and abrasive jet perforation.

Figure 3 graphically illustraa fracturing pumping schedule according to the present disclosure.

Figure 4 is a photograph of a cavern or perforation made by an abrasive jet technique.

Figure 5 is a flow diagram illustrating a drilling and pumping schedule in accordance with the present disclosure.

Detailed description The present disclosure is directed to the combination of improved abrasive jet drilling techniques that enable the creation of discrete conglomeraof perforations separated by non-perforated intervals, and subsequently improved hydraulic fracturing techniques including the emission of agent pulses. of shoring. Any amount from one to 100 or more conglomeracan be treated together and each cluster can include from one to 20 or more perforations. Each conglomerate can be up to 5 m or more in length and the non-perforated intervals can vary from about 10 cm to about 5 m or more in length. The abrasive jet perforation can optionally be done through flexible tubing and subsequent fracturing techniques can optionally be performed through an annular gap created by the flexible tubing and the casing. Of course, other techniques may be employed, as will be apparent to those skilled in the art.

Abrasive jet drilling may have advantages over cumulative drilling in that the abrasive jet drilling may allow a selective approach for drilling the conglomerate location and a non-drilled interval between drilling conglomera The abrasive jet perforation may also allow a significant reduced amount of perforations within the casing, but it may still provide a risk-free entrainer of bracing agent due to the large surface area of the caverns created within the cement and the formation by abrasive jet drilling techniques. In addition, such caverns can connect the drilling well with the fracture.

In one embodiment, an abrasive punching scheme may include conglomeraof perforations up to 5 meters in length and may also include non-perforated intervals between the conglomerawhich may vary from about 10 cm to 5 m or more in length. The number of conglomerafor fracturing treatment can vary from 1 to 100, or any suitable number, depending on factors such as formation thickness, drilling well deviation and fracture design parameters. The number of perforations in each cluster can vary from 1 to 20 or more, or any suitable number, depending on factors such as the characteristics of training and specific issues in the design of fracture treatment. In one case, each cluster may include from 1 to 6 perforations or caverns created in azimuthally different directions by fluid jet flow through nozzles of the perforating device. An illustration of a perforation scheme of this type is shown in figure 1 and an illustration of an abrasive jet perforation device is shown in figure 2.

Figure 1 shows a sectional view of a drilling well 10 that has been coated with a casing 11 with the annular space disposed between the casing and the formation 12 being loaded with cement 13. Figure 1 illustrates a plurality of drilling conglomerates 14 which, in the embodiment illustrated in Figure 1, each include one to four perforations 15 forming caverns extending through cement 13 and into the interior of formation 12. The conglomerates 14 can be separated from one another by non-perforated intervals 16. Although each cluster 14 can be treated separately using the improved hydraulic fracturing techniques disclosed hereinafter, each cluster 14 can also be treated simultaneously using the hydraulic fracturing techniques that are disclosed.

An abrasive jet drilling tool 19 for forming the conglomerates 14 shown in Figure 1 is illustrated in Figure 2. The tool 19 includes a collet locator / centering 20, a connector 22, and a sandblasting adapter 23. Collator locator / collet 20 is connected below connector 22, which can be used to couple tool 19 to a flexible pipe (not shown) or another string of tools (not shown). The collet locator 20 is used to determine when the tool 19 is within a particular area of interest in the well on the basis of the collars 24 found in the well casing pipe 11 (Figure 1). Although the embodiment of Figure 2 includes a neck locator / collator 20, this device may be one of a number of different devices in the background of the well used to determine the location of a downhole assembly within a drilling well 10. The disconnecting tool 22 can releasably connect the tool 19 to the end of a flexible pipe, string of tools, Drill pipe, cable line, etc. A reverse check valve with a rounded tip 25 is disposed at a distal end of the tool 19.

Once the tool 19 has been located within the new area of interest and the sandblasting adapter 23 is placed in the proper location, a fluid loaded with abrasive can be pumped at a high pressure through the jet accesses. on the outside of the sandblasting adapter 23. For example, Ottowa 20/40 sand can be pumped through the sandblasting adapter 23 to create the perforations 15 through the casing 11 in the desired locations as described. shown in Figure 1. The use of Ottowa 20/40 sand pumped through the sandblasting adapter 23 can perforate the casing 11 and cement 13 in the area of interest in as little as twenty minutes. The tool 19 can also be used to drill a pipe as would be appreciated by one skilled in the art who has the benefit of the present disclosure. The configuration of the jet accesses 27 of the sandblasting adapter 23 can be varied to change the number and locations of the perforations created by the sandblasting adapter 23. The configuration of the individual jet accesses 27 can also be changed to modify the cutting power of the sandblasting adapter 23.

After the casing 11 (or pipe) has been perforated as shown in Figure 1, the tool 19 can be removed from the drill hole 10 or, if the tool 19 is disposed at one end of a flexible pipe ( not shown), the tool can move away from the perforations 15 to provide a sufficient annular flow path to allow stimulation of the perforations 15.

The fracturing fluid is pumped down the casing 11 at a high pressure in an attempt to generate fractures through the perforations 15 in the areas of interest.

In a hydraulic fracturing method for an underground formation, a first phase referred to as the "fluid phase without shoring agent" involves injecting a fracturing fluid into a drilling well at a high enough flow rate. so that it creates a hydraulic fracture in the formation. The fluid phase without shoring agent is pumped until the fracture is of sufficient dimensions to accommodate the pumped back slurries in the shoring agent phases. The volume of the fluid without shoring agent can be designed by those skilled in the art of fracture design.

Water-based fracturing fluids are common with natural or synthetic water-soluble polymers added to increase fluid viscosity and are used throughout the fluid phases without bracing agent and the subsequent with binder agent. These polymers include, but are not limited to, guar gum; high molecular weight polysaccharides composed of mannose and galactose sugars; or guar derivatives, such as hydropropyl guar, carboxymethyl guar, and carboxymethylhydropropyl guar. Common crosslinking agents based on boron, titanium, zirconium or aluminum complexes are commonly used to increase the effective molecular weight of the polymer making it more suitable for use in high temperature wells.

To a lesser extent, cellulose derivatives, such as hydroxyethylcellulose or hydroxypropylcellulose and carboxymethylhydroxyethylcellulose, with or without crosslinking agents are used. Two biopolymers - xanthan and scleroglucan - show an excellent shoring agent suspension capacity, but they are more expensive than guar derivatives and, therefore, are used less frequently. Polyacrylamide and polyacrylate polymers and copolymers are commonly used for applications high temperature or as friction reducers at low concentrations for all temperature ranges.

Water-free, polymer-free fracturing fluids can be obtained using viscoelastic surfactants. In general, these fluids are prepared by mixing appropriate surfactants, such as anionic, cationic, nonionic and Zwitterionic, in appropriate amounts. The viscosity of the viscoelastic surfactant fluids is attributed to the three-dimensional structure formed by the fluid components. When the concentration of surfactants in a viscoelastic fluid significantly exceeds a critical concentration, and in most cases in the presence of an electrolyte, the surfactant molecules are aggregated giving species, such as worm-like or bar-type micelles. , which can interact to form a network that shows a viscous and elastic behavior.

After the "fluid phase without shoring agent", several phases, referred to as "shoring phases", are injected into the formation. A phase of shoring involves the periodic introduction into the fracturing fluid in the form of solid particles or granules to form a suspension. The phase with bracing agent is divided into two secondary phases that are repeated periodically, the "secondary carrier phase" involves the injection of the fracturing fluid without bracing agent; and the "secondary shoring phase" involves the addition of shoring agent in the fracturing fluid. As a result of periodic formation of grout plugs containing granular shoring materials, the shoring agent does not completely fill the fracture. Instead, separate shoring agent conglomerates are formed as pillars with channels therebetween through which the forming fluids pass. The volumes of the secondary shoring and carrier phases as pumped may be different. That is, the volume of the secondary carrier phases may be larger or smaller than the volume of the secondary phases of the carrier. shoring. In addition, the volumes of these secondary phases may change over time. That is, a secondary phase of shoring pumped ahead of time in the treatment may be of a volume smaller than a phase Another pumping schedule is illustrated graphically in figure 3. In table 1 and figure 3, "dirty pulse" refers to "secondary shoring phase" and I "Clean impulse" refers to "secondary carrier phase". Referring to Figure 3, the first phase, which is referred to as the fluid phase without shoring agent, is shown at 31. A plurality of shoring agent phases are shown at 32-37 in which, each phase of agent of Shoring 32, 33, 34, 35, 36 represents the injection of a fracturing fluid loaded with shoring agent having increasing concentrations of shoring agent. Within each phase, 32, 33, 34, 35, 36, pulses of "clean" fracturing fluid are followed by pulses of fracturing fluid (or slurry) dirty or loaded with shoring agent. The At for each pulse can vary widely with respect to the 12-second example given in Table 1. For example, clean and dirty impulse times can vary from about 5 seconds to one minute or longer; pulse times in the range of about 5 seconds to about 30 seconds. The final tail input phase is shown at 37 and has a zero clean impulse volume.

Some concepts such as support for an abrasive drilling scheme of this type to promote the creation of channels within the fracture after treatment with the bracing agent impulse emission technique include the following: (1) The area near the well of Drilling is the most critical area for the entry of shoring agent (high tangential stresses). The disclosed technique can allow a reliable undercoating agent entry and a reduction in the risk of obturation by shoring agent. This can be achieved even with a lower number of holes inside the casing than the number of holes that would be necessary with a cumulative drilling technique. The reduced number of holes in the interior of the casing would be achieved by the geometry of the abrasive cavern - which has a larger contact area with the fracture in relation to the contact area generated from a channel developed with the Cumulative drilling technique. An abrasive cavern is created without excessive temperatures or pressures and without damaging the surface around it. (2) Due to the better entry of shoring agent, it is possible to decrease the total number of drilling holes without increasing the risk of plugging by shoring agent (an orifice of perforation by conglomerate in some cases) to increase the bypass pressure resulting in the enhancement of the injection profile (all conglomerates admit grout). A better division of a shoring agent impulse into smaller structures is achieved by conglomerates in the drilling well, before the grout enters the fracture. (3) The decrease in the number of perforations within a given drilling interval can be beneficial at terminations where several fractures are to be initiated during the injection of fracturing fluid. An example is the initiation of several transverse fractures in a horizontal drilling well in which a fracture is to be initiated through each drilling conglomerate. The more perforations are created within a conglomerate, the less predictable is the number of fractures initiated. If the number of perforations within a conglomerate is not sufficient for an appropriate shoring agent entry (eg, cumulative perforations), then no fracture can be created in a given conglomerate. If the number of perforations is too large, then more than one fracture can be created within a conglomerate. An accurate estimate of the number of fractures created is necessary for an appropriate design of a fracturing job. For example, the number of fractures created can affect the choice of duration for the "secondary shoring phase" and the "secondary carrier phase". Therefore, the use of abrasive perforations with a small number of holes within a conglomerate can result in a more reliable design of the fracturing treatment. (4) Conglomerates can be adapted in their separation from one another to guarantee optimal channel creation. Conglomerate sizes, distances between clusters, hole density, variations in hole density within a specific cluster, hole sizes, hole size variations within a specific cluster can easily be adjusted to suit changes of the geomechanical properties of the formation if it is used abrasive drilling. One of the characteristics of a drill gun is the density of shots. The inverse of the value of the shot density is the separation between shots or the distance between shots. If conventional punching guns are used then the conglomerate height and the distance between conglomerates should be a multiple of the separation between shots. Abrasive drilling has no such limitations. The size of the hole and the geometry of the drilling channel in the cumulative drilling depend on the thickness of the casing, the type of load and the properties of the rock. For cumulative drilling, parameters such as hole size and channel geometry are limited by gun and load specifications. In the case of abrasive drilling, the grout rate and the cutting duration can be chosen during the treatment to adapt the hole size and the geometry of the cavern.

Reinforcing and / or consolidating material can be introduced into the fracture fluid during the bracing phase to increase the strength of the binder formed conglomerates and prevent their collapse during fracture closure. Usually the reinforcing material is added to the secondary shoring phase, although this may not always be the case. The concentrations of both reinforcing and shoring materials can vary over time through the entire shoring phase, and from secondary to secondary phase. That is, the concentration of reinforcing material can be different in two subsequent secondary phases. In some applications of the present method it may also be suitable to introduce the reinforcing material continuously throughout the entire phase with the shoring agent, during the secondary phases of both carrier and shoring. In other words, the introduction of reinforcement material is not limited to the secondary stage of shoring. In particular, different implementations may be preferable when the concentration of the reinforcing material does not vary during the entire phase with binder; increases monotonically during the phase with shoring agent; or decreases monotonously during the phase with shoring agent.

Bracing agent coated with hardenable or partially hardenable resin can be used as reinforcing and consolidating material to form binder conglomerates. The process of selecting the suitable resin-coated brazing agent for a particular bottom hole static temperature (BHST), and the particular fracturing fluid are well known to those skilled in the art. In addition, organic and / or inorganic fibers can strengthen the conglomerate of shoring agent. These materials can be used in combination with resin coated or brazing agents separately. These fibers could be modified to have only one adhesive coating; or an adhesive coating coated by a layer of non-adhesive substance dissolvable in the fracturing fluid as it passes through the fracture. Fibers made of adhesive material can be used as a reinforcing material, coated by a non-adhesive substance which dissolves in the fracturing fluid as it passes through the fracture at the underground temperatures. The metal particles are another preference for the reinforcing material and can be produced using aluminum, steel containing special additives that reduce corrosion, and other metals and alloys. The metal particles can be shaped to resemble a sphere and measure 0.1-4 mm. Preferably, metal particles of an elongated shape with a length greater than 0.5 mm and a diameter of 10 to 200 microns are used. Additionally, plates of organic or inorganic substances, ceramics, metals or metal-based alloys can be used as reinforcement material. These plates may be disk-shaped or rectangle-shaped and of such length and width that, for all materials, the ratio between the largest and smallest dimensions is greater than 5 to 1.

The secondary phases of both carrier and shoring can include the introduction of an agent in the fracturing fluid to increase the transport capacity of the shoring agent. In other words, reduce the decanting rate of the binder in the fracture fluid. The agent can be a material with elongated particles whose length far exceeds its diameter. This material affects the rheological properties and suppresses the convection in the fluid, which results in a decrease in the decanting rate of the binder in the fracture fluid. The materials that may be used include fibers that are organic, inorganic, glass, ceramic, nylon, carbon and metal. The shoring agent transport agents may be capable of decomposing in the water-based fracturing fluid or in the downhole fluid, such as fibers made from poly (lactic acid), poly (glycolic acid) ), poly (vinyl alcohol), and others. The fibers may be coated or made of a material that becomes adhesive at the temperatures of underground formation. These can be made of adhesive material coated with a non-adhesive substance that dissolves in the fracturing fluid as it passes through the fracture. The fibers used can be longer than 0.5 mm with a diameter of 10-200 microns, according to the main condition that the ratio between the largest and smallest dimensions is greater than 5 to 1. The concentration in weight of the fibrous material in the fracturing fluid sees from 0.1 to 10%. The shoring agent should be chosen taking into account the strength of the shoring agent conglomerates. In one embodiment, the fibers may be made of poly (lactic acid), poly (glycolic acid) or copolymers comprising glycolic acid and / or glycolic acid. In another embodiment, the fibers are added at a concentration of 0.5 to 20 kg per m 3 of fracturing fluid.

A conglomerate of shoring agent should maintain a reasonable residual thickness at full fracture closure tension. The present method provides an increase in the inflow of fluid through open channels formed between the shoring agent conglomerates. In this situation, a The permeability value of the shoring agent, as such, is not decisive for increasing the productivity of the well using the present method. Therefore, a conglomerate of shoring agent can be successfully created using sand whose particles are too weak for use in conventional hydraulic fracturing in the present formation. The sand costs substantially less than the ceramic shoring agent. Additionally, the destruction of the sand particles during the application of the fracture closure load could improve the resistance behavior of the same conglomerate consisting of bracing agent granules. This can take place because the cracking / destruction of the shoring agent particles decreases the porosity of the conglomerate, thereby increasing the degree of compactness of shoring agent. Sand pumped into the fracture to create shoring agent conglomerates does not need good granulometric properties, ie a narrow particle diameter distribution. For example, it is possible to use 50 tons of sand, where 10 to 15 tons have a particle diameter of 0.002 to 0.1 mm, 15 to 30 tons have a particle diameter of 0.2 to 0.6 mm, and 10 to 15 tons have a particle diameter of 0.005 to 0.05 mm. It should be noted that approximately 100 tons of a more expensive shoring agent than sand would be necessary to obtain a similar value of hydraulic conductivity in the created fracture that implements the previous (conventional) method of hydraulic fracturing.

It may be preferable to use sand with only an adhesive coating, or an adhesive coating coated with a layer of non-adhesive substance dissolvable in the fracturing fluid as it passes through the fracture. A non-adhesive substance guarantees that the particles of the adhesive binder will not form agglomerates before entering the fracture, and allows control of a moment in time (a place) in the fracture in which (where) a particle of agent of shoring gains its adhesive properties. The coating Adhesive hardens at the forming temperature, and the sand particles adhere to each other. The bonding of particles within the conglomerates reduces the rate of erosion of the shoring agent conglomerate because the formation fluids flow beyond the conglomerate, and minimizes the destruction of conglomerate of erosion shoring agent.

In some cases, the shoring phase may be followed by a shoring agent phase, which is referred to as the "tail entry phase" in Figure 3, which involves a continuous introduction of a quantity of blowing agent. shoring. If used, the tail entry phase of the fracturing treatment resembles a conventional fracturing treatment, in which a continuous bed of bracing agent is placed in the fracture relatively close to the drill hole. The tail entry phase can involve the introduction of both an agent that increases the carrying capacity of the binder of the fluid and / or of an agent that acts as a reinforcing material. The tail entry phase is distinguished from the second phase by the continuous placement of a well-sized shoring agent, ie, a shoring agent with an essentially uniform particle size. The strength of the shoring agent is sufficient to prevent cracking (crushing) when subjected to the stresses that occur in the fracture closure. The role of the shoring agent in this phase is to avoid fracture closure and, therefore, to provide good fracture conductivity in the vicinity of the drill hole.

The disclosed methods of hydraulic fracturing introduce one or more agents into the treatment fluid to promote the formation of binder-like conglomerates in the fracture during pumping, while propping agents are continuously pumped. When the agent reacts, this results in the local formation of a conglomerate of shoring agent. Usually the agent is selected or designed in such a way that its action or function is delayed until it is placed inside the fracture. The retarding of a chemical and physical reaction is a process commonly used in hydraulic fracturing as well as in many other industrial processes. A process that can be used is the simple activation by temperature of the agent as the fracturing fluid heats up as it enters the higher temperature formation deep in the earth. For example, the homolysis of ammonium persulfate is relatively slow at surface temperatures of 20 ° C, but relatively fast at the formation temperatures of 100 ° C. A second process is a slow dissolution of a reactive agent, or a binder. For example, the dissolution ratio of polyvinyl alcohol in water depends on its molecular weight. The encapsulation of a reactive species is a common process used in hydraulic fracturing. The material or reactive agent is protected for a time from the fracturing fluid by a relatively non-reactive capsule. The encapsulated material subsequently releases the reactive agent, either slowly or rapidly by many different methods. The encapsulation can be designed to release its contents by dissolution, mechanical erosion, crushing, swelling and rupture, or simply by slow diffusion.

The first phase of the fracturing treatment, the "fluid phase without shoring agent" (figure 3) is pumped as usual. Unlike the previous embodiment in which bracing agents were pumped in a batchwise manner, the bracing agent (bracing agents) is pumped continuously. The concentration of the shoring agent can increase, remain constant, or decrease during the shoring agent phase. Normally, the binder agent concentrations start low, and gradually rise to higher concentrations near the end of the treatment. The key of the present embodiment is that an agent gives rise to the nucleation or the formation of conglomerates of binder agent is introduced batchwise or periodically into the fracturing fluid during the phase with shoring agent. The agent is designed to work in only a small region or area within the fracture. The shoring materials within this area are influenced in such a way that they form a conglomerate, form seals and remain immobile. In addition, the shoring agents that are pumped after the conglomerate formation can accumulate on the conglomerate and make the size of the conglomerate grow.

One way to generate clusters of shoring agent is to locally reduce the ability of the fluid to transport particles in solid phase. In the present case, the agent could be a high concentration of oxidative "breakthrough agents", such as ammonium persulfate, which, when reacted with the fracturing fluid at different places in the fracture, leads to drastic and significant decreases in the local viscosity of the fracturing fluid. When the fluid viscosity falls below a critical value, the fracturing fluid can not transfer the binder agent particles and the particles are stopped, decanted, and conglomerates of binder are formed. The addition of fibers greatly enhances the formation of conglomerate of shoring agent. Encapsulated rupture agents with a long release time can be used at the beginning of the phase with binder, and encapsulated rupturing agents with short release times can be used at the end of the phase with binder.

Reinforcing materials such as fibers can greatly increase the tendency of the bracing agents to bind locally between the fracture walls and form a conglomerate. Therefore, in the present embodiment, fibers and / or other reinforcing materials may be added to the fracturing fluid as discussed above during the brazing agent phase either continuously or discontinuously (as described above). same time as the rupture agent).

The requirements for the propping agent properties used in the first embodiment are also applied in the second. It is possible to use a shoring agent without a narrow particle diameter distribution, i.e., a poorly rated shoring agent with a relatively small resistance value per particle. For example, there may be sand particles with coatings similar to those described in the first embodiment of the method. The third phase that has been mentioned above can also take place.

The chemical species that competitively bind the common crosslinking agents could be any other type of agent used to locally reduce the viscosity of the fluid. The localized release of chelants, (which react with zirconate crosslinking agents), sorbitol or polyvinyl alcohol (which react with borate crosslinking agents) or other species that deactivate the crosslinking agent can cause the polymer gel The viscosity of the fracturing fluid is significantly reduced and reduced. Since many crosslinking reactions are pH dependent, the localized release of an acid or base can also reduce the fluid viscosity. For example, the pH of the fracturing fluid can be manipulated through the introduction of an encapsulated acid and / or particles of substances, for example poly (lactic acid) or poly (glycolic acid) in which the release or generation of the acid It occurs at a controlled rate. Changing the pH of the fracturing fluid reduces the affinity of the crosslinking agent to form stable bonds with the polymer and the viscosity of the fluid decreases for certain combinations of specific polymer crosslinking agent.

For these purposes, an encapsulated absorbent or competitive chelating agent of the polymer chain crosslinking agent can also be used, which allows a controlled release. Cross-linked gel chemicals, such as sodium gluconate or sorbitol, can be used for a borate. For metal crosslinking agents, such as titanates or zirconates, chemical products can be used including but not without limitation to EDTA, NTA, phosphates, poly (vinyl acetates). The selection of the specific chemical to attack the crosslinking agent in question is well known to the experts. Such absorbers can be, for example, phosphates or polyvinyl acetates.

The agent that provides conglomerate formation of underpinning agent by decreasing the local viscosity of the fracturing fluid can also represent chemicals that react with the fracturing fluid to provide a significant amount of localized heat extraction, resulting in heating of the fracturing fluid and thereby decreasing its local viscosity. Examples of such substances include explosives or encapsulated reactive metals such as sodium, which release the substance at various places in the fracture to provide for the formation of conglomerate of binder throughout the length of the fracture.

Conglomerates of shoring agent and channels can be formed between the clusters by reducing the mobility of the shoring agent in the fracture. The present method includes the fluid phases without shoring and shoring agent that have been described above, but differs in that the agents that produce conglomerate formations reduce the mobility of the shoring agent particles.

Specifically, the additives can be bundles of fibers that expand slowly and emit individual fibers due to mechanical agitation. The increased volume excluded from the beam and the localized increase in the concentration of fibers can initiate clogging and create conglomerates of shoring agent.

The additives can also be cut wires made of an alloy having "shape memory" properties. For example, copper-aluminum-nickel form memory alloys (CuAINi) function throughout the temperature range of many oil and gas-containing formations. These Materials can be bent to form small balls (springs) and retain their shape at surface temperature. When heated up to the reservoir temperature, the material with "shape memory" undergoes phase transition accompanied by recovery of its original memorized straight line shape. The variation of phase transition temperature is possible by varying the composition of the alloy. It may be preferable to introduce a material whose phase transition temperature varies from portion to portion. At the beginning of the shoring agent phase, for example, it may be reasonable to introduce materials with the highest phase transition temperature, for example, slightly lower than the formation temperature; and at the end of the second phase it may be reasonable to introduce a material having the lowest phase transition temperature, for example, slightly more than the surface fluid temperature. The balls of the "shape memory" material are usually similar in size to the shoring agent particles.

When the metal balls are subjected to a high temperature in the fracture, they recover their original shape, that is, they straighten. As indicated above, a localized increase in its content effectively promotes the formation of conglomerates of bracing agent in the fracture. The ability to vary the recovery temperature gradually by varying the alloy composition allows for the formation of cables and thus immobile conglomerates of biasing agent evenly distributed across the entire length of the fracture.

The use of super-absorbent material to form clogs located in the fluid fractg fluid can also be used. Super absorbers such as crosslinked polyacrylamide polyacrylate copolymers can absorb an amount of water of 100 to 300 times their weight in water. A wide variety of super-absorbers are available. The selection of a particular one can be determined by factors such as the formation temperature, the content in salt of the water used to prepare the fractg fluid, and others.

A super absorbent may be used that is protected by a coating or emulsion that dissolves or disperses as it passes through the fracture or with the increase in fracture fluid temperature, or a combination of these conditions. By varying the thickness of the cover, it is possible to control the time interval between introducing a portion of the super absorbent into the fractg fluid and releasing it from the cover. When the cover dissolves or disperses, an absorbent particle begins its growth by absorbing water from its surroundings. The increase in mass and particle size decelerates its movement through the fracture and ultimately results in localized clogging, the capture of shoring agent particles, and the formation of shoring agent conglomerates.

Additives may also be used to reduce the mobility of binder in the fracture may be granules, fibers, or plates whose surface becomes "adhesive" at the formation temperatures. Additional coating of particles with adhesive surfaces with a layer of a non-adhesive substance dissolvable in the fractg fluid may be preferable; by varying the thickness of the substance, the time interval can be varied whose duration results in the formation of conglomerates of shoring agent due to its surface adhesive properties. Another technique for controlling the time interval employs coatings that gain adhesive properties at different temperatures. It may be preferable to introduce particles with a maximum thickness of the protective coating (therefore, with a maximum demonstration temperature of "adhesive" properties) at the beginning of the second phase. And it may be preferable to introduce respectively particles with a minimum thickness of a protective coating (therefore, with a minimum demonstration temperature of "adhesive" properties) at the end of the second phase. When such particles enter the fracture, they collide (collide) and adhere to each other forming agglomerates of particulate matter. shoring. When the size of the agglomerates becomes comparable with the characteristic width of the fracture, they are wedged between the fracture interfaces causing local bindering agent clogging and the formation of bindering agent conglomerates.

The use of reinforcing materials with the fractg fluid can also be employed, thereby increasing the strength of the formed shoring agent conglomerates; and introducing agents that increase the transport capacity of the binder agent of the fluid by decreasing the rate of decanting of the binder agent through the fractg fluid. All of these requirements for the selection of shoring agent, particularly for the use of a shoring agent that is relatively strong in a moderate way, a (possibly) wide distribution of particle sizes, the shoring agent preliminarily coated with a layer of hardening binder under the conditions of formation, are still applicable.

The formation of shoring agent conglomerates and channels therebetween by sequential pumping of two fluids with viscosities that contrast to the interior of the drill hole can be employed. The present method involves a fluid phase without shoring agent as discussed above, and the shoring phase involves the continuous introduction of shoring agent in a given fluid. Similar to the previous embodiments, the shoring phase may involve introducing reinforcing materials into the fracturing fluid, these materials increasing the strength of the shoring agent conglomerates formed; and introducing an agent that increases the transport capacity of the binder agent of the fluid by decreasing the decanting rate of binder agents. All the requirements for the selection of shoring agent, particularly the use of a shoring agent with a relatively moderate strength, a wide distribution of particle sizes, and preliminarily coated with a layer of hardening binder under the conditions of formation, are still applicable.

Then the injection of fracturing fluid containing binder agent content together with other materials is finished, and a very low viscosity fluid is injected into the fracture created. Due to the difference between their viscosities, the injection of the lower viscosity fluid after the injection of the more viscous fluid results in the penetration of the lower viscosity fluid into the more viscous fluid in the form of "intrusions". This forms channels in the shoring agent that fills the fracture by dividing the shoring agent into discrete conglomerates.

As discussed above, a fourth "tail entry" phase can involve a continuous introduction of a shoring agent with an essentially uniform particle size, a reinforcing material, and / or a material with elongated particles. which increase the carrying capacity of the shoring agent of the fracturing fluid to the fluid.

All of the methods for hydraulic fracturing described above and with different mechanisms for forming shoring agent conglomerates provide very high hydraulic fracture conductivity. This occurs through the formation of strong shoring agent conglomerates well separated throughout the length and height of the fracture. The conglomerates are sufficiently stable to prevent the fracture from closing; and the inter-conglomerate channels have a cross section large enough for the formation fluids to flow.

Industrial Applicability Figure 5 is a flow diagram illustrating another disclosed combination of improved abrasive jet and fracturing techniques. The part 41 means the placement of the drilling tool 19 disclosed inside the borehole 10. The tool 19 is located within the area of interest in part 42. An initial drilling cluster 14 is created within the abrasive jet in part 43. In part 44, tool 19 relocates to a new area of interest. In part 45, a new conglomerate 14 is drilled. In part 46, fracturing fluid without shoring agent is pumped down the casing pipe 11. This is referred to above as the fluid phase without shoring agent, which is also illustrated in Figure 3. Then, in part 47, slurry loaded with underpinning agent is pumped down the casing 11 and parts 46 and 47 are sequentially repeated for a concentration of shoring agent given in part 48 as illustrated in Figure 3. Then, another slurry loaded with biasing agent is pumped down the casing 11 in the 49th part, and then pumping clean fracturing fluid in the 50th part. The parts 49-50 can be repeated then in part 51 and the pattern shown in figure 3 can be followed.

Although only some exemplary embodiments have been described in detail in the foregoing, those skilled in the art will readily appreciate that many modifications to the exemplary embodiments are possible without departing materially from the spirit and scope of the invention. present disclosure. The features shown in individual embodiments referred to above can be used together in combinations other than those that have been specifically shown and described. Accordingly, it is intended that all such modifications be included within the scope of the present disclosure as defined in the following claims.

Claims (15)

CLAIMS What is claimed is:

1. A method for drilling and fracturing an underground formation with a drilling well lined with a casing extending through at least part of the formation, the method comprising: forming a first conglomerate of at least one perforation through the casing and into the formation with hydroabrasive jets; injecting a fracturing fluid free of shoring agent into the drill hole through the first conglomerate; combining the fracturing fluid free of shoring agent with a shoring agent to form a first slurry loaded with shoring agent and injecting, alternately and repeatedly, the first slurry loaded with shoring agent, and subsequently injecting the fracturing fluid free of shoring agent inside the drill hole and through the first conglomerate.

2. The method of claim 1 further comprising: combining one of the free-crushing fluid of shoring agent with additional shoring agent to provide one or more additional binder-laden slurries of varying concentrations of shoring agent and for each slurry loaded with additional shoring agent, to inject in a manner alternative and repeated, each slurry loaded with additional shoring agent, and subsequently inject the free fracturing fluid of shoring agent into the drilling well and through the at least one conglomerate.

3. The method of claim 1, wherein the one or more grouts loaded with additional shoring agent have a different concentration of shoring agent than the first slurry loaded with shoring agent.

4. The method of claim 1 further comprising: forming a second conglomerate of at least one perforation through the casing and into the formation with hydroabrasive jets, in which the second conglomerate is separated from the first conglomerate by a non-perforated interval; injecting the fracturing fluid free of propping agent into the drill hole through the first and second conglomerate simultaneously; injecting, alternately and repeatedly, the first slurry loaded with bracing agent, and subsequently injecting the free fracturing fluid of bracing agent into the drilling well and through the first and second conglomerate simultaneously.

5. The method of claim 1, wherein the non-perforated interval has a length ranging from about 10 cm to about 5 m.

6. The method of claim 1, wherein each of the first and second conglomerates includes from about 1 to about 10 perforations.

7. The method of claim 1 further comprising: form from 1 to about 100 additional conglomerates; injecting the free fracturing fluid of the bracing agent into the drill hole through all the conglomerates simultaneously; injecting, alternately and repeatedly, the first slurry loaded with bracing agent, and subsequently injecting the free fracturing fluid of bracing agent into the drilling well and through all of the conglomerates simultaneously.

8. The method of claim 1, wherein the injection of each of the first slurry loaded with shoring agent, and subsequently the injection of the fracturing fluid free of shoring agent is carried out along a series of substantially uniform pulses.

9. The method of claim 1, wherein the fracturing fluid also includes fibers.

10. The method of claim 3, wherein the fracturing fluid also comprises fibers.

11. The method of claim 6, wherein the fracturing fluid also comprises fibers.

12. The method of claim 1, wherein the formation of the first conglomerate and that is carried out through flexible tubing, and the injection, alternately and repeatedly, of the first slurry loaded with binder, and subsequently the injection of the binder. free fracturing fluid of bracing agent inside the drilling well and through the first conglomerate is made through an annular separation between the flexible pipe and the casing.

13. A method for drilling and fracturing an underground formation with a drilling well lined with a casing extending through at least part of the formation, the method comprising: (a) forming a first conglomerate through the casing and into the formation with hydroabrasive jets; (b) injecting a fracturing fluid free of proppant into the drill hole through the first conglomerate of perforations; (c) combining the fracturing fluid free of shoring agent with a shoring agent to form a first slurry loaded with shoring agent; (d) injecting the first slurry loaded with shoring agent to through the first conglomerate; (e) repeat parts (b) and (d) alternatively.

14. The method of claim 13 further comprising: (a) (1) forming a second conglomerate through the casing and into the formation with hydroabrasive jets, with an unperforated interval between the first and the second conglomerate; (b) (1) injecting the fracturing fluid free of binder into the drill hole and through the first and second conglomerate simultaneously; Y (d) (1) injecting the first slurry loaded with binder agent through the first and second conglomerate simultaneously, (e) (1) repeat parts (b) (1) and (d) (1) alternatively.

15. The method of claim 14, wherein the non-perforated interval has a length ranging from about 10 cm to about 5 m.