Polymer liquid with initiated thickening for pumping to formation and methods for its application

FIELD: oil and gas industry.

SUBSTANCE: treatment method of underground hydrocarbon-containing formations involves the following: a) provision of a composition including a thickening initiator measuring pH, and a polymer capable of hydration in a certain pH range; b) pumping of a composition with pH value beyond the limits of the above pH range; c) activation of an action of pH thickening initiator for displacement of pH composition to the above range of its values, and d) provision of a possibility of increasing viscosity of the composition and shaping of a plug. According to another version, a processing method of underground hydrocarbon-containing formations involves the following: a) provision of a composition containing a polymer capable of hydration in a certain pH range; b) pumping of the composition with pH value beyond the limits of the above pH range; c) provision of a pH changing thickening initiator; d) activation of the action of the thickening initiator for displacement of pH composition to the above range of its values, and e) provision of a possibility of increasing viscosity of a composition and shaping of a plug. The invention has been developed in dependent claims.

EFFECT: improving efficiency of initiation and control of plug formation.

15 cl, 5 ex, 3 dwg

 

Cross-reference to related application

[0001] the present application claims priority on the filing date of provisional patent application U.S. serial number 12/976395, titled "liquid Polymer initiated with may for the injection into the reservoir and its applications", filed on 22 December 2010, which is incorporated herein by reference in full.

Area of technology

[0002] the Present invention relates mainly to the exploitation of hydrocarbon reservoirs or injection wells. More specifically, the present invention relates to chemical separation or displacement of the layers and based on the properties of hydration of some biopolymers, mainly Gurovich derivatives.

The level of technology

[0003] the Description in this area provide only basic information associated with this description, and may not constitute prior art.

[0004] the Hydrocarbons (oil, condensate and gas) are typically extracted from wells that are drilled in the containing layers. For a number of reasons, such as low, at its core, the permeability of the reservoir or formation damage caused by drilling and completion of wells, the flow of hydrocarbons into the well is at an unacceptably low level. In this case the well "stimulate", for example, using the hydraulic bit�VA, chemical (usually acid) stimulation or a combination of the two (called the acid fracturing or acid fracturing).

[0005] Hydraulic fracturing involves the injection of fluids into the formation under high pressure and at high speed, so that the reservoir rock has collapsed, forming a gap (or the network breaks). To prevent the closure of cracks after reducing the pressure in tearing liquids are usually introduced after the pillows propping agents. When handling the chemical (acid) stimulation, photochemisty increases due to dissolution of materials in the layer.

[0006] When hydraulic and acid break usually in the first layer is injected viscous liquid called "cushion" for the initiation and propagation of the rupture. Then enter the second fluid, which contains a propping agent to prevent the closure of cracks after reducing the pressure. Granular propping agents may include sand, ceramic balls or other materials. When "acid" break the second liquid contains acid or another chemical, such as a chelating agent that can dissolve a portion of rock, causing uneven etching of the surface of rupture and destruction of a certain amount of mineral substances, leading to the fact that RA�gap is not closing completely when you stop the discharge. Sometimes hydraulic fracturing is performed without a high-viscosity fluid (reagent water-based) in order to minimize costs polymers or other thickeners.

[0007] When a hydraulic fracture stimulation or chemical stimulation of the multilayer gas-bearing zones, it is desirable to process multilayer zones in several stages. When you break multilayer zone is broken first producing zone. Then tearing the liquid is discharged to the next stage for the break following a productive zone. This process is repeated until the gap all productive zones. Alternatively, several productive zones can be broken simultaneously, if they are close and have similar characteristics. The withdrawal may be effected in various ways, including the formation of temporary pillow using polymer gels or solid materials, regulating water loss.

[0008] Polymer gels are widely used to align the injectivity profile of natural fissured/fractured reservoirs. Review of existing polymeric compositions shown in U.S. patents Nos. 5486312 and 5203834, where also listed a number of patents and other sources related to gel-forming polymers.

[0009] the Authors present application have discovered a way to initiate and control the formation of traffic jams.

To�way description of the invention

[0010] In the first aspect of the disclosed method. This method comprises providing a composition comprising the initiator thick of changing pH and polymer capable of hydratious in a certain area pH; injection of the composition with a pH that is outside of the defined area of pH, activation of the initiator of the action thickens to shift the pH of the composition is within the specified pH region; and providing the possibility of increasing the viscosity of the composition and formation of the tube.

[0011] In a second aspect, the disclosed method of treatment of underground formations in the wellbore. This method includes obtaining a composition containing a polymer capable of hydratious in a certain area pH; injection of the composition with a pH that is outside of the defined area pH; delivery of the initiator thick of changing pH; activation of the initiator of the action thickens to shift the pH of the composition in this range of pH values; and providing the possibility of increasing the viscosity of the composition and formation of the tube.

[0012] In a third aspect, the disclosed method of separation or displacement of the strata in the well bore. This method comprises providing a composition containing a resin capable of hydratious in a certain pH region; injecting into the well a composition with a pH that is outside of the defined area pH; delivery of the initiator sagusa�ing, changing pH; activation of the initiator of the action of thickening to shift the pH of the composition in the specified area of its values and providing opportunities to increase the viscosity of the composition and formation of the tube.

Brief description of graphic material

[0013] figure 1 shows a graph depicting the rate of hydration CMHPG at different pH.

[0014] figure 2 is a graph depicting the hydration of the polymer in one embodiment, the accelerated release of the acid-initiated effects of temperature.

[0015] figure 3 shows a graph depicting the hydration of the polymer according to the second embodiment, the accelerated release of the acid-initiated effects of temperature.

Detailed description

[0016] Initially, it should be noted that when developing any real options, you must make numerous decisions, depending on the specific method of implementation, to achieve certain goals of the developer, such as the constraints of the system and business, which may vary from one embodiment to another. Moreover, it should be understood that such development can be complex and time-consuming, but, nevertheless, they must be made in the prescribed manner by those skilled in the field, which has the advantage of real� description.

[0017] the Present description and examples are presented only to illustrate variants of the present invention and should not be construed as limiting the scope and applicability of the present invention. In the spirit of the invention and the detailed description, each numerical value should first be read as modified by the term "about" (if it is already remodification so), and then to read how not modified thereby, unless the context indicates otherwise. Also in the essence of the present invention and the detailed description it should be understood that the concentration ranges listed or described as applicable, or similar suitable, mean any or each concentration within the range, including the boundary values should be considered as given. For example, range from 1 to 10" should be read as indicating each and every possible number in a continuous range from about 1 to 10. Thus, even if specific data points are inside the range, or even if within the range, there are no data points that are clearly specified or mentioned only for some particular cases, it should be understood that the inventors assume and consider that any and all data points in this range, should be considered as specified, and that the authors of the invention belongs to the full range of sun�x of the points in the described range and they are entitled to the full range and all points within this range.

[0018] the Following definitions are provided for ease of understanding by professionals in this area a detailed description of the present invention.

[0019] the Term "gap" refers to the process and methods of destruction of geological and create a gap, that is, the rock around the wellbore by pumping fluid under very high pressure, to increase the impact of reservoir hydrocarbons. Everything else in the ways of the gap used standard techniques known in this field.

[0020] In accordance with the first warrant, the method comprises providing a composition comprising the initiator thick of changing pH and polymer capable of hydratious within a region of pH values; the injection of the composition with a pH outside the specified region of the pH; the activation of the initiator of the action thickens to shift the pH of the composition in the specified area of its values; and providing the possibility of increasing the viscosity of the composition and formation of the tube.

[0021] Certain range of pH is from about pH 0 to about pH 8.5, or from about pH 2 to about pH 8, or from about pH 3 to about pH 8, or from about pH 3.5 to about pH 7,5.

[0022] the viscosity Increase of more than 150 GPa, and tube formation is performed in less than 10 minutes or even less than 5 minutes, to allow the rapid formation of p�obci.

[0023] the Composition may be obtained in the form of an aqueous solution. The aqueous solution may be a solution of fresh water or an aqueous solution comprising a salt of one-, two -, or trivalent metals, ammonium and mixtures thereof. The salt may be present naturally, if brine is used, or may be added in aqueous solution. For example, to water you can add any salt such as a salt of an alkali metal or alkaline earth metal salt (NaCO3, NaCl, KCl, and so on). Salt is usually contained in a weight percentage concentration from about 0.1% to about 5%, from about 1% to about 3% by weight. One of the applicable concentration is about 2% by weight. For some applications, in particular, are expected to be freezing, the aqueous solution may further comprise an alcohol, such as methanol, ethanol, propanol or polyhydric alcohol such as glycerin or polyglycols, or mixtures thereof.

[0024] the Resin capable of hydratious may be any crosslinked polymer. The polymer may be a metal-crosslinked polymer. Suitable polymers for obtaining metal-crosslinked polymers include, for example, polysaccharides, such as substituted galactomannans, such as guar gums, high-molecular-weight polysaccharides consisting of sugars mannose and galactose, or guar derivatives, such as cationic guar derivatives, such as qualitatsprodukten chloride and similar hydroxypropyl guar (HPG), carboxymethyloxime guar (CMHPG) and carboxymethyl guar (CMG), hydrophobically modified guary, guar-containing compounds and synthetic polymers. To increase the effective molecular weight of the polymer and improve their suitability for use in high temperature wells are typically used, chevauchee agents on the basis of complexes of boron, titanium, zirconium or aluminium.

[0025] Other suitable classes of polymers include polyvinyl polymers, polymethacrylamide, cellulose ethers, langoulant and their ammonium salts, chitosan, alkali metals and alkaline earth metals. More specific examples of other standard water-soluble polymers are copolymers of acrylic acid-acrylamide, copolymers of acrylic acid-methacrylamide, polyacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamide, polyvinyl alcohol, polyalkylene, other galactomannans, heteropolysaccharides obtained by the fermentation of starch sugars, and their ammonium salts and alkali metal.

[0026] To a lesser extent, using cellulose derivatives, such as hydrocellulose (HEC) or hydroxypropyl cellulose (HPC), (CMHEC) and carboxymethylcellulose (CMC) with cross-linking agents. It was shown that Xan�EN, deutan and scleroglucan, three biopolymer, have excellent ability to form a suspension of solid particles, despite their higher cost compared to garavini derivatives and therefore less frequent use, except for possible use at lower concentrations.

[0027] In other embodiments, the polymer is prepared from sew, Gidrodinamika polymer and crosslinking agent in slow motion, where the crosslinking agent comprises a compound including a metal and a first ligand selected from the group consisting of amino acids, phosphonic acids and their salts or derivatives. Cross-linked polymer can also be obtained from a polymer comprising lateral ion fragments, of a surfactant comprising oppositely charged fragments, anticoagulant clay, a source of borate and metal stapler. These options are described in patent publications U.S. US2008-0280790 and US2008-0280788, respectively, each of which is incorporated herein by reference.

[0028] the Initiator pH may be organic or inorganic acid. The initiator pH can be liquid, solid or encapsulated acid. The initiator pH can be encapsulated in microspheres or be in emulsion or suspension in some liquid medium.

[0029] In one embodiment, the initiator pH yavl�is encapsulated acid with a protective coating. The protective coating is liable to break when the temperature changes, in fact, regardless of the time. In another embodiment, the protective coating can break down when the temperature changes depending on time.

[0030] In one embodiment, the polymer used is a polymer guar derivative. For hydration of these biopolymers need a certain pH range. Outside this pH range hydration is very slow or non-existent. In the case of the guar derivative resin, a dependence of the rate of hydration from pH may depend on the specific conditions of production. One of the stages of the production process includes stitching in soft conditions Gurovich plates with borates. The crosslinking reaction occurs at alkaline pH (usually above 9), and the resulting polymer has basic properties. Borate cross-linking, which remain stable at a pH in excess of 8.5-9, holds the molecules Guara together, preventing the penetration of water molecules into the polymer pellets and slowing down, so hydration. The chemical removal of cross-links by reducing the pH, the polymer molecules takes place and instantly is hydrated, leading to swelling of the polymer granules and a sharp increase in viscosity.

[0031] an Example of the dependence of hydration from pH are presented in figure 1, where a 1.25% (by weight) suspension CMHPG in water �e-hydrated and, therefore, does not cause any increase in viscosity at a pH of 10.5, 11.0 to 11.6. While lowering the pH to 7.7 with a few drops of HCl, instantly is hydrated, which leads to a sharp increase in viscosity.

[0032] the Composition may further comprise a degradable material. The biodegradable material can be biodegradable fibers or particles derived from biodegradable polymers. The difference of molecular structures degradable materials provides greater opportunity to control the speed of decomposition of the degradable material. When the degradable material should take into account the resulting decomposition products. For example, some may form during the decomposition of the acid, and the presence of acid may be undesirable; others may form insoluble decomposition products, which may be undesirable. In addition, these decomposition products should not adversely impact on other production processes or components.

[0033] the Degradation of the polymer depends, at least in part, from the structure of its skeleton. One of the most common structural characteristics is the presence of hydrolyzed and/or oxidized connections in the skeleton. The rate of decomposition, for example, polyesters depends on the type repeating units, composition, consistently�ti, length, molecular geometry, molecular weight, morphology (e.g. crystallinity, size and orientation of the spherulites), hydrophilicity, surface area, and additives. In addition, the decomposition of the polymer can influence the conditions that affect the polymer, for example, temperature, presence of moisture, oxygen, microorganisms, enzymes, pH, and the like. Specialists in this field, which has the advantage of the present invention, can determine the optimum polymer for a given application based on the characteristics of the polymer and the conditions that it is exposed to.

[0034] Suitable examples of polymers that can be used contain, but not be limited to, homopolymers, statistical copolymers of aliphatic polyesters, block copolymers of aliphatic polyesters, star-shaped copolymers of aliphatic polyesters or hyperbranched copolymers of aliphatic polyesters. Such applicable polymers can be obtained by polycondensation reactions, polymerization with ring opening, free-radical polymerization, anionic polymerization, carbocationic polymerization, coordination polymerization with ring opening, for example, lactones, and any other suitable means. Specific examples apply�s polymers include polysaccharides, such as dextran or cellulose, chitins; chitosans; proteins; aliphatic polyesters; poly(lactide); poly(glycolide); poly(ε-caprolactone); simple and complex mixed poly(hydroxyether); poly(hydroxybutyrate); polyanhydride; polycarbonates; a complex of poly(orthoevra); poly(acetals); poly(acrylates); poly(alkylacrylate); poly(amino acids); poly(ethylene oxide); simple and mixed polyesters; complex polyester-amides; polyamides; polyphosphazene; and their copolymers and mixtures. You can also specify other degradable polymers that can undergo hydrolytic degradation. One guides the selection of composite particles for use in a particular application are generated decomposition products. Other management conditions are present for a particular application.

[0035] Of these applicable preferred polymers are aliphatic, the polyesters. From applicable aliphatic polyesters are preferred polyesters of α or β-hydroxy acids. Most preferred is poly(lactide). Poly(lactide) is synthesized from lactic acid condensation reaction or, more often, by polymerization of cyclic lactides monomer by ring opening. Lacheny monomer usually exists in three different forms: two stereoisomers, L - and D; and D,L-lactide (meso-lactide). Chirality lactide links provides the ability to regulate, among other things, the rate of decomposition, and physical and mechanical properties after polymerization of lactide. Poly(L-lactide), for example, is a semicrystalline polymer with a relatively low rate of hydrolysis. This may be desirable in those applications where a low decomposition of degradable material. Poly(D,L-lactide) is an amorphous polymer with a much higher rate of hydrolysis. Stereoisomers of lactic acid can be used individually or combined for use in the compositions and methods of the variants of the present invention. In addition, they can be copolymerizable, for example, glycolide or other monomers such as ε-caprolactone, 1,5-dioxan-2-CT, trimethylantimony, or other suitable monomers for polymers with other properties or decomposition. In addition, the stereoisomers of lactic acid can be modified by blending with high-molecular or low-molecular-weight polylactide or mixing of polylactide with other complex aliphatic polyesters. For example, the rate of decomposition of polylactic acid may depend on mixing, for example, high-molecular or low-molecular-weight polylactic acid called PLA; smesa�and polylactide and lactides monomer; or from mixing of polylactide with other complex aliphatic polyesters.

[0036] the Physical properties of degradable polymers may depend on several factors such as the composition of repeating units, flexibility of the chain, the presence of polar groups, molecular weight, degree of branching, crystallinity, orientation and so on. For example, short branches reduce the crystallinity of the polymers, while the long branches reduce the viscosity of the melt and attach to, among other things, the longitudinal viscosity characteristics of stiffness in tension. The properties of the material used can be further adjusted by blending and copolymerization with another polymer or a change in the macromolecular structure (for example, hyperbranched polymers, star-shaped or dendrimers, and so on). The properties of any such applicable degradable polymers (such as hydrophilicity, rate of biodegradation, and so on) can be adjusted by the introduction of functional groups along the polymer chains. Specialists in this field, which has the advantage of the present description, can determine the appropriate functional groups which need to be implemented in the polymer chain to achieve the desired effect.

[0037] In some embodiments, the degradable material is presented in the form �of renal, powder, spheres, ribbons, plates, fibers, flakes, or any other shape with an aspect ratio of equal to or greater than one. In some embodiments, the degradable material includes particles having a dimension ratio of more than 10, 100, 200, 250 or the like, such as plates or fibers, or the like. Composite materials can take any form of composites, for example, the biodegradable material is coated or skeleton structure made of other materials dispersed therein. In addition, the degradable particles may be nano-, micro - or mesoporous structures are fractal or refractility.

[0038] In the following embodiment, the composition may further include additives such as diluents, antioxidants, corrosion inhibitors, retarding agents, biocides, buffers, regulating water loss additives, pH-regulators, solid acid, precursors of solid acids, organic inhibitors of salt deposits, inorganic inhibitors of salt deposits, demolicious agents, inhibitors of parafinoterapija, corrosion inhibitors, inhibitors of the formation of gas hydrates, chemical substances for cleaning asphaltenes, foaming agents, regulating water loss agents, water-resistant agents, agents for enhanced oil recovery or the like. Dobavkamai also be a biological agent.

[0039] the Composition is compatible with other fluids or materials, such as, for example, hydrocarbons such as mineral oil, propping agents or additives that are typically used to stimulate the well. Embodiments of the present invention can be used in various applications, including the temporary creation of traffic jams, the destruction of the tubes or multiple stages of rupture for the treatment of subterranean formations having a plurality of zones of different permeability.

[0040] the method includes the injection wellbore composition and providing opportunities to increase the viscosity of the composition to create a tube. This application can be used for stimulation of discontinuities in new or redesigned horizontal or vertical wells to achieve okolozemnogo drain by opening up totally new areas for processing or re-stimulate, which effectively increases the previous stimulation of the existing older areas of the gap.

[0041] To facilitate a more complete understanding of some of the options are presented the following examples of options. The following examples should not in any way be considered as limiting or defining the scope of the options described in this document.

Examples

[0042] To demonstrate the properties of the compositions and methods described above, would� performed a series of experiments.

Example 1

[0043] 5% (by weight) suspension CMHPG in water was prepared by mixing 10 g of CMHPG with 200 ml of demineralized water. Then brought to pH 10 by adding 2 drops of 10% NaOH solution. The viscosity of the mixture is increased for 24 hours at room temperature.

[0044] To a freshly prepared 5% suspension CMHPG added a few drops of concentrated HCl, so that the pH decreased to 6.6. When adding acid to the viscosity of the system is instantly increased. In just a few seconds it is fully hardened.

Example 2

[0045] 5% (by weight) suspension of cationic guar (Ecopol 14) in water was prepared by mixing 10 g of powder Ecopol 14 with 200 ml of demineralized water. Then brought to pH 10 by adding 2 drops of 10% NaOH solution. The viscosity of the mixture is increased for 24 hours at room temperature.

[0046] To a freshly prepared 5% suspension Ecopol added 14 grams of fumaric acid, so the pH decreased to 3.2. When adding acid to the viscosity of the system is instantly increased. In just a few seconds it is fully hardened.

Example 3

[0047] 5% (by weight) suspension of cationic guar (Ecopol 14) in water was prepared by mixing 10 g of powder Ecopol 14 with 200 ml of demineralized water. To the mixture was added 0.2 g of encapsulated ammonium persulfate. Then brought to pH 10 by addition of several drops of 10% NaOH solution. The viscosity of the mixture is increased for 24 hours at room temperature.

[0048] To a freshly prepared 5% suspension Ecopol added 14 grams of fumaric acid, so the pH decreased to 3.0. When adding acid to the viscosity of the system is instantly increased. In just a few seconds it is fully hardened.

[0049] Then, the system was placed in an oven at 150°F to facilitate the release of ammonium persulfate from the encapsulation. After 24 hours gelled polymeric liquid completely destroyed with the formation of a liquid with the consistency of water.

Example 4

[0050] 1,5% (by weight) suspension of cationic guar (Ecopol 14) in water was prepared by mixing 3 g of powder Ecopol 14 with 200 ml of demineralized water. Then brought to pH 10 by addition of several drops of 10% NaOH solution. The resulting mixture was tested in the rheometer Grace 5600 at 100 c-1and temperatures 70-180°F. After 3 hours has not been found to increase viscosity.

[0051] in the same manner was prepared two samples of 1.5% (by weight) suspension of cationic guar (Ecopol 14).

[0052] Before testing them on the device Grace 5600, Cup rheometer added 0.2 and 0.5 grams of encapsulated fumaric acid (content of active substance 60%), respectively. To test used the same temperature program. In both cases, once the temperature has initiated the release of fumaric acid from the encapsulation, there has been rapid hydration with an immediate increase in viscosity. The results of these ISP�of the tests are presented on figure 2.

Example 5

[0053] 5% (by weight) suspension of cationic guar (Ecopol 17) in water was prepared by mixing 10 g of powder Ecopol 17 with 200 ml of demineralized water. Then brought to pH 10 by addition of several drops of 10% NaOH solution. The resulting mixture was tested in the rheometer Grace 5600 at 100 with-1and temperatures 70-180°F. After 3 hours has not been found to increase viscosity.

[0054] in the same manner was prepared two samples of 5% (by weight) suspension of cationic guar (Ecopol 17).

[0055] Before testing them on the device Grace 5600, Cup rheometer added 0.2 and 0.5 grams of encapsulated citric acid (content of active substance 70%), respectively. To test used the same temperature program. In both cases, once the temperature has initiated the release of citric acid from the encapsulation, there has been rapid hydration with an immediate increase in viscosity. The results of these tests are presented in figure 3.

[0056] Specific options described above are only illustrative, since the present invention can be modified and implemented other, but equivalent ways, understandable to specialists in this field, which have the advantage presented in this guidance document. In addition, the details described in this document are not intended for any og�of anichini, in addition to those described below in the claims. Therefore, it is clear that the specific options described above may be altered or modified and all such variations are included within the scope of the variants described herein, Respectively, herein sought to be protected is set forth below in the claims.

1. Method for treatment of a subterranean hydrocarbon reservoir, comprising:
(a) providing a composition comprising the initiator thickening of changing pH and polymer capable of hydratious in a certain area pH;
(b) injection of the composition with a pH value outside the specified area pH;
(C) activation of the initiator of the action of thickening pH offset pH of the composition in the specified area of its values; and
(d) providing opportunities to increase the viscosity of the composition and formation of the tube.

2. A method according to claim 1, characterized in that the polymer is selected from the group consisting of ditana, xantana, Guara, Gurovich derivatives and mixtures thereof.

3. A method according to claim 1 or 2, characterized in that the polymer is selected from the group consisting of CMHPG, CMG, HPG, cationic Gurovich derivatives, such as guar, hydroxypropyltrimonium chloride, and the like, and mixtures thereof, and wherein the polymer is present in a concentration of from about 1 to about 15% by weight.

4. A method according to claim 1 or 2, characterized in that the defined�bedroom area pH is from about 2 to about 8.

5. A method according to claim 1 or 2, characterized in that the step of forming the tube is less than 10 minutes.

6. A method according to claim 1 or 2, characterized in that the initiator of thickening of changing pH selected from the group consisting of organic acids, inorganic acids, encapsulated acid, a latent acid, acid emulsion, acid slurry and mixtures thereof.

7. A method according to claim 6, characterized in that the encapsulated acid contains a protective coating and acid, and a protective coating is biodegradable, at least under the influence of time or temperature.

8. A method according to claim 1 or 2, characterized in that the composition further comprises a biodegradable material, which are fibers of polylactic acid (PLA).

9. A method according to claim 1 or 2, characterized in that the composition further comprises at least crosslinking agent or a diluent.

10. Method for treatment of a subterranean hydrocarbon reservoir, comprising:
(a) providing a composition containing a resin capable of hydratious in a certain area pH;
(b) injection of the composition with a pH value outside the specified area pH;
(C) providing an initiator thickening of changing pH;
(d) activation of the initiator of the action of thickening to shift the pH of the composition in the specified area of its values; and (e) providing for the possibility of increasing the viscosity of the composition and formation of the tube.

11. A method according to claim 10, which is used for treatment of a subterranean formation into the wellbore.

12. A method according to claim 10 or 11, characterized in that the initiator of thickening is introduced into the well bore on a pipe.

13. A method according to claim 10 or 11, characterized in that the pipe selected from the group consisting of casing pipes, flexible pipes with microdeletion, flexible pipe, production pipe, the pipe of the downhole tool, and combinations thereof.

14. A method according to claim 10 or 11, characterized in that the step of forming the tube is less than 10 minutes.

15. A method according to claim 10, characterized in that this method is a method of separation or displacement of the reservoir.



 

Same patents:

FIELD: oil and gas industry.

SUBSTANCE: in a carbonaceous oil deposit development method that includes drilling of horizontal wells with a core sampling from the productive formation, performance of core laboratory tests, acid treatment and multiple hydraulic fracturing of the formation in these wells, according to the invention the core is sampled at different sections along the whole length of the horizontal shaft. The sampled core is subjected to the laboratory tests to determine the fracturing pressure, at that the sections are identified along the shaft where the minimum fracturing pressure Pmin, MPa, and the maximum fracturing pressure Pmax, MPa is required. Each section is treated by acid; at that the acid concentration for each section is set as identical. During the acid treatment each treated section of the formation is isolated temporarily by packers from the remaining part of the well. Then multiple proppant hydraulic fracturing of the formation is made under pressure that does not exceed Pmax. At that at the sections, where Pmax is required the acid treatment is performed in a volume of Qmax, m3/m, at the sections where Pmin is required the acid treatment is performed in a volume not exceeding 10% of the maximum value. At the remaining sections the volume of the injected acid is defined proportionally to the obtained fracturing pressure in compliance with the following ratio: Qn=QminQmaxPminPmax(PnPmin)+Qmin, where Qn is the specific volume per meter of the thickness, which is required for the injection to the nth section of the formation along the horizontal shaft, m3/m, Pn is the required fracturing pressure at the nth section of the formation along the horizontal shaft, MPa.

EFFECT: improved sweep efficiency and increased oil recovery of the oil deposit.

1 dwg

FIELD: oil and gas industry.

SUBSTANCE: method includes running of production string with packer in to the well, setting of the packer, hydraulic fracturing by injecting fracturing fluid through production string with packer to the producing reservoir with further proppant injecting through perforated interval in the low-permeable bed, pressure releasing from the well. Additionally perforated interval in the low-permeable bed is isolated temporary, the interval of clay layer is perforated using alternating charges of large diameter and deep invasion; then the production string with packer is lowered so that the lower end of the production string is at the level of clay layer roof, the packer is set in the well, the low-permeable bed is fractured with formation of cracks by injection of fracturing fluid along the production string through perforated intervals in clay layer. Then bank of oil-based cross-linked gel is injected to cracks in volume of 3-5 m3 with flow rate of 10 m3/min. Proppant moisture is used as proppant. Then cracks are reinforced by dosed injection of fracturing fluid and proppant mixture starting with concentration of 400 kg/m3 for proppant mixture with stepped increase of its concentration in fracturing fluid per 200 kg/m3 for each dose and flow rate of 5 m3/min. The proppant mixture is made at the wellhead with the following ratio of components, wt %: proppant 12/40 mesh - 30%; proppant 18/20 mesh - 30%; quartz flour - 40%. Upon completion of hydraulic fracturing of low-permeable bed temporary isolation is removed from the perforated interval of the low-permeable bed with formation of hydraulic connection between the borehole and created fracture.

EFFECT: improved reliability of hydraulic fracturing for low-permeable bed with clay layers and bottom water.

1 dwg

FIELD: oil and gas industry.

SUBSTANCE: in the method of well operation stimulation including test injection of breakdown fluid and package of breakdown fluid with proppant, correction of the breakdown project and performance of fracturing in low-permeable reservoirs having absolute permeability less than 1mD, hydraulic fracturing is made with injection of flush fluid on the basis of 1.0-3.0 m3 per 1 t of proppant using proppant fractions, which include only fine fraction with size less than 30/60 mesh with final concentration of proppant less than 300 kg/m3; at injection of the fluid flow rate of 3.5 m3/min and more and concentration of gel formation is set less than 2 kg/m3, with final underflush of the mixture in volume of 0.1-0.5 m3.

EFFECT: simulation of the well opening the low-permeable formation.

3 ex

FIELD: mining.

SUBSTANCE: method involves drilling of a horizontal well, lowering to a vertical part of the well of a casing string and its cementing, lowering of a pipe string with a packer to a well, seating of the packer, formation of fractures of formation hydraulic fracturing (FHF) in the horizontal well shaft by pumping via the pipe string of fracturing fluid, and fixation of fractures by pumping of carrier fluid with proppant. The horizontal shaft is drilled perpendicular to direction of minimum main stress. FHF is performed by pumping of fracturing fluid with flow rate of 2-3 m3/min with formation of a longitudinal fracture in the formation relative to the open horizontal part of the well; crosslinked gel is used as fracturing fluid; then, fixation of a longitudinal fracture is performed by pumping via the pipe string of proppant of large fraction with carrier fluid - crosslinked gel. Then, FHF is performed by pumping of fracturing fluid with flow rate of 7-9 m3/min; line gel is used as fracturing fluid; after that, fixation of branched FHF fractures is performed by pumping of proppant of small fraction with carrier fluid - line gel.

EFFECT: improving FHF efficiency and reliability.

2 dwg

FIELD: oil and gas industry.

SUBSTANCE: method comprises test forcing of fracturing fluid and pile of fracturing fluid with proppant, correcting the fracturing project and performing of the main fracturing process. In highly permeable reservoirs with absolute permeability not less than 100 mD the main fracturing process is carried out with usage of proppant fractions, which include initial fraction with mesh size from 30/40 up to 20/40 and the main coarse fraction with mesh size of 12/18 and more in the volume not less than 70% of the total proppant quantity with final proppant concentration not less than 750 kg/m3. While injecting fraction with mesh size of 12/18 and more through perforated openings fluid consumption is set so that it does not exceed 3 m3/min and wellhead pressure is maintained at the level less than 35 MPa.

EFFECT: improving the efficiency of hydraulic fracturing for highly permeable strata.

1 tbl

FIELD: chemistry.

SUBSTANCE: invention relates to a propping agent and use thereof in hydraulic fracturing for oil and gas extraction. The ultralight propping agent is prepared from a mixture of raw materials comprising porcelain clay, pottery clay and kaolin and/or siliceous clay, in the following content, wt %: porcelain clay 5-85, kaolin and/or siliceous clay5-85, pottery clay 5-30. The ultralight propping agent with apparent specific gravity of 2.10 g/cm3 to 2.55 g/cm3 and volume density of 1.30 g/cm3 to 1.50 g/cm3 is prepared from a mixture of natural clays comprising porcelain clay, pottery clay and at least kaolin or siliceous clay, where alumina content is 5.5-35%. In the method of preparing said filler, high strength of the propping agent is achieved by controlling firing time in the range of 75-90 minutes and firing temperature of 1150°C to 1380°C. Sintered spherical granules prepared from a mixture of raw materials comprising porcelain clay, pottery clay and at least kaolin or siliceous clay, having a substantially circular or spherical shape, are characterised by a Krumbein coefficient of at least 0.8 with alumina content of 5.5-35%. The hydraulic fracturing method includes pumping into an underground formation a hydraulic fluid with flow rate and pressure sufficient for opening a fracture in the formation, and the fluid containing said filler is pumped into the fracture.

EFFECT: high strength of the propping agent and conductivity thereof.

29 cl, 13 tbl, 5 ex

FIELD: mining.

SUBSTANCE: method involves drilling of a horizontal well shaft, lowering and fixation of a shank with filters, lowering of a packer and its seating, formation of cracks in each of the zones, which correspond to intervals of parts of the horizontal shaft with insulation of the rest of its parts. With that, the lower end of a pipe string is located 1 m closer to the mouth from the distant formation interval; a string of flexible pipes is lowered into the above pipe string and it is equipped from below with an abrasive jet perforator; space between the pipe string and the string of flexible pipes is sealed at the well mouth. Groups of slit perforation holes are made with length of 20-30 cm and width of 15 mm with a phasing angle of 60° in every 1.5 m of the oil-saturated formation interval in the shank; reverse flushing is performed together with simultaneous movement of the string of flexible pipes from the mouth to the face throughout the length of the oil-saturated formation interval; the string of flexible pipes with a jet nozzle is removed, and hydraulic formation fracturing is performed with further fixation of a fracture by light-weight resin-coated propping agent with fraction size of 20/40 mesh in concentration of 1400 kg/m3 and its filling to the horizontal well shaft opposite the oil-saturated formation interval; the packer is removed; the pipe string is moved in the direction from the face to the mouth to the next oil-saturated formation interval; after that, the above operations are repeated starting from seating of the packer and ending with the packer removal in the rest oil-saturated formation intervals developed by the horizontal well shaft.

EFFECT: improving reliability of hydraulic formation fracturing and efficiency of fracture fixing.

4 dwg

FIELD: mining.

SUBSTANCE: method comprises the formation exposing by vertical well, tripping in the well on the pipe string of the water jet tool with even amount of injection nozzles and its placement in the preset interval of the formation, injection of driving fluid through injection nozzles of the water jet tool for caving in the formation, subsequent formation fracturing from caverns by the spray stagnation pressure in caverns. Meanwhile the water jet tool with a series of injection nozzles, located along the tool with the interval between nozzles in a line no more than two diameters of the casing is used. The water jet tool is rotated to the preset angle to change the direction of progressing of each subsequent fracture. The fractures are formed at driving fluid injection pressure in the casing below the side rock pressure. Before tripping of pipe string into the well in the bottom end of the water jet tool the rotating device and mechanical packer are installed. To compensate leakages and the wedging of fractures during the process of hydraulic formation fracturing an acid is added in volume equal to 20% of the volume of the driving fluid, the driving fluid is injected into the pipe string through the water jet tool into a cavern until fracturing, then into the annular space of the well an acid is injected to compensate the leakages and fracture wedging. The pressure of acid injection into annular space of the well amounts 85% from the pressure created in the pipe string during progressing of fracture, upon termination of progressing fracture and the wedging of fracture in the same direction raise a pipe string on 1 m, turn a pipe string on an angle applicable to a direction of forming of following fracture, and lowered, then the process operations are repeated.

EFFECT: improvement of accuracy of orientation of fractures, performance and reliability of fracturing of carbonate reservoirs.

3 dwg

FIELD: mining.

SUBSTANCE: method comprises the drilling of a horizontal well bore in oil saturated part of the productive formation of the well, tripping of the pipe string into the well, the forming of perforations and fractures using the a hydrofracturing of formation in the hole of horizontal well, successively, starting from the end of far from the vertical borehole axis. During the next hydrofracturing the section, through which hydrofracturing is performed, is insulated from another part of the string with a packer. During drilling of the horizontal well bore the permeability and porosity of rocks are determined and the intervals of the productive formation with low permeability and porosity of rocks are identified, and on completing of drilling the rock hydrofracturing pressure is determined in each interval of the horizontal borehole. Then the volumes of fracturing fluid and acid for each interval of the oil saturated part of the formation with low permeability and porosity are determined, then the pipe string is moved to the interval of the productive formation nearest to the borehole bottom, with low permeability and porosity, the mechanical packer is seated, from hole mouth using the pumping unit the gelled fracturing fluid is injected into the pipe string through nozzles of the water jet tool and reshape perforations, then, not stopping injection gelled of fracturing fluid on a pipe string, construct fracture pressure applicable to the given interval of the oil saturated part of the productive formation. After 30% drop of pressure of injection of gelled fracturing fluid in the pipe string the hydrofracturing fractures are formed, for this purpose into the annular space of the well an acid is injected at the variable flow rate ensuring maintaining of pressure of injection of gelled fracturing fluid in the pipe string 10% less than the fracture pressure for the given interval of the oil saturated part of the productive formation. The packer releasing is performed and the pipe string is removed from bottomhole to the mouth into the following interval of the oil saturated part of the formation with low permeability and porosity of rocks for forming perforations and conducting of a hydrofracturing of the formation with forming and progressing of fractures.

EFFECT: shortening time for formation hydrofracturing, improvement of performance and reliability of formation hydrofracturing.

3 dwg

FIELD: oil-and-gas industry.

SUBSTANCE: invention relates to subsurface formations processing in the production of hydrocarbons. Method of processing a subsurface formation crossed by a hole comprises: preparation of a processing fluid containing a viscoelastic surfactant with at least one degradable link, a hydrolysable material and a pH adjusting material. Note here that the latter has a pH value equal to or larger than 9 and contains a strongly alkaline substance and an oxidiser. The said processing fluid is injected in the subsurface formation. The invention is developed in dependent claims.

EFFECT: higher efficiency of the proppant transportation and decomposition at low temperatures.

21 cl, 1 tbl, 14 dwg

FIELD: oil-and-gas industry.

SUBSTANCE: invention relates to oil production, particularly, to from underground oil deposits. In compliance with this invention, at least one production well and one injection well can be used. Temperature distribution in the zone between said wells is analysed. In case temperature is distributed between said zones so that minimum temperature makes at least 20°C, maximum temperature does not exceed 320°C, while their difference makes at least 20°C, aqueous gel-forming preparations are injected via injection well that contain one or several chemical components. These preparations after injection in the deposit form gels under the effects of deposit temperature. Said preparations differ in type and/or concentration of chemical components. Chemical components and/or their concentration are selected to make gel-forming temperature and/or geol-forming time of the second and, if required, any other injected portion, differ from portions injected there before.

EFFECT: higher efficiency of oil extraction due to levelling of injectivity.

19 cl, 4 tbl, 7 dwg

FIELD: oil and gas industry.

SUBSTANCE: according to the method the first and second banks are injected through a hydrocarbon- or water-based displacement fluid to the designed area of the well. At that the availability of a residual saturation area is determined in productive formations with loose - loosely cemented porous and/or fractured reservoirs. The availability of an ultimate water saturation area, an undersaturated transition interval with a film water area and an intensive flow of water diffuse layers and a subarea of high oil content is determined. The availability of ultimate oil saturation is determined. The availability or unavailability of shale barriers at boundaries of the ultimate water saturation area and the transition interval is considered. The water saturated area is cut from the ultimate oil saturation area and an oil inflow is ensured to the productive formation from the subarea of high oil content. Injection is made to the design area of a producer and/or injector. At that the displacement fluid in injected in a quantity of 0.1 up to 500% of the first bank volume. The second bank is injected in a quantity of 0.1-250% of the first bank volume. Polymer resin is used as the first bank. Polymer hardener is used as the second bank. Upon injection the well is transferred to the hydrocarbon inflow mode.

EFFECT: increased efficiency of the method.

24 cl, 47 ex, 1 dwg

FIELD: oil and gas industry.

SUBSTANCE: in the development method of a non-homogeneous oil formation that includes injection to the formation of an aqueous solution of polyacrylamide (PAA), chrome acetate and magnesium oxide, the solution contains additionally a glass or basalt reinforcing microfiber pretreated by a 1-5% aqueous solution of AF9-6 or AF9-12 or constructional reinforcing microfiber (CRF) with the following concentration of components in the solution, wt %: PAA 0.3-1.0, chrome acetate 0.03-0.1, magnesium oxide 0.015-0.07, the above fibre 0.1-0.5.

EFFECT: increased efficiency of the method.

1 dwg, 2 tbl, 1 ex

FIELD: oil and gas industry.

SUBSTANCE: invention is related to hydrocarbons from underground formation. The method of raw oil recovery from a reservoir, including at least one oil-bearing porous underground subsurface with connate water and oil in cavities of the rock pores having API density less than 25° and containing suspended undissolved solids (SUS), lies in injection of input water to the rock, wherein the input water contains SUS and total content of dissolved solids (TCDS) in it is equal to 30000 ppm or less, the ratio of total content of multivalent cations (MC) in the input water to total MC content in connate water is less than 0.9, and receipt of water-in-oil emulsion inside hydrocarbon-bearing rock; total SUS content in the input water and raw oil is sufficient for SUS content in emulsion to be at least 0.05% per emulsion mass and SUS in the input water is equal to at lest 0.05 kg/m3 and average size of particles is 10 mcm or less, raw oil in pores contains at least 0.05% of SUS with the same average size, total acid number (TAN) of oil is at least 0.5 mg of KOH/g, asphaltene content in it is at least 1-20 wt % and resin content is 5-30 wt %. The invention also suggests increase in recovery degree of raw oil from the above reservoir with connate water and oil in cavities of the rock pores having API density less than 25° and containing SUS with average diameter less than 2 mcm in quantity equal to at least 0.01 wt %, with TAN of at least 0.5mg of KOH/g, asphaltene content of at least 1 wt % and resin content of 5-30 wt %, and the input water is injected to the rock in order to receive water-in-oil emulsion in it, where this water is collected by determination of MC content in connate water, extraction of the input water containing dissolved solids (DS) in quantity less than 30000 ppm, the total MC content is such that the ratio of total MC content in the input water to total MC content in connate water is less than 0.9 and contains at least 0.05 wt % of SUS with average diameter less than 2 mcm in the above water. Invention has been developed in dependent claims.

EFFECT: improving washing efficiency and reducing quantity of residual oil in the rock.

9 cl, 3 ex, 4 dwg, 4 tbl

FIELD: oil and gas industry.

SUBSTANCE: invention refers to the oil and gas production industry and can find application in developing heterogeneous terrigene or carbonate producing beds. In the method for an oil bed development, involving the oil bed water-flooding, injection of water solution banks containing alkali, a polymer, a surfactant, a microorganism culture and a nutrient medium, into injection holes, and sampling of products from the production wells, at the initial stage a deposit is developed by water-flooding in an amount adequate to achieve the collected compensation of water-flood liquid sampling of not less than 50%; once the oil sampling reaches 70% of the initial recovered reserves, residual prospective oil distributed over specific 1 m2 is mapped; the worked-out compartments are detected to inject the above solution into the centre injection holes with the following proportions, wt %: alkali - no more than 5, polymer - no more than 1, surfactant - no more than 0.5, microorganism culture - no more than 0.05, nutrient medium - no more than 0.5, water - the rest with varying the concentration C of the ingredients in the above solution proportional to the specified prospective oil for each C centre is determined depending on Cnk=ynCmaxk, wherein k is a type of the ingredient, n is the number of the centre, y is a proportionality factor of each centre; y is calculated by a linear equation y=a·x+b, wherein x is the specific prospective oil of the centre, t/m2, a, b are linear equation factors determined if y for xmax equals to 0, and if xmin equals to 1 from a system of equations wherein xmax and xmin are the maximum and minimum specific prospective oil values, respectively; injection cycles of the bank injection are repeated if an oil flow rate decreases to the pre-injection level.

EFFECT: higher displacement factor and better oil recovery of the productive formation.

1 ex

FIELD: oil and gas industry.

SUBSTANCE: invention refers to the oil and gas industry and can be used in developing heterogeneous terrigene or carbonate producing viscous-oil beds. In the method, which involves an oil bed water-flooding, injection of water solution banks containing alkali, a biopolymer, a surfactant, a bacterial culture and nutrient salts, into injection holes, and sampling of products from the production wells; deposit drilling is followed by mapping the formation permeability distribution in the wells with the formation permeability more than twice less than the average formation permeability; if the collected oil withdrawal is no more than 50% of the initial recovered reserves, the formation is hydraulically fractured; oil sampling findings are used to map the oil-viscosity compartment distribution; the above solution is injected in the compartments through the injection holes in the following proportions, wt %: alkali - no more than 5, biopolymer - no more than 1, surfactant - no more than 0.5, hydrocarbon-oxidising bacterial culture - no more than 0.1, nutrient salts - no more than 0.8, water - the rest with varying the concentration C of the ingredients in the above solution proportional to the specified OV for each C centre is determined depending on Cnk=ynCmaxk, wherein k is a type of the ingredient, n is number of the centre, y is a proportionality factor of each centre; y is calculated by a linear equation y=a·x+b, wherein x is the OV of the centre, mPa·s, a, b are linear equation factors determined if y for xmax equals to 1, and if xmin equals to 0 from a system of equations: wherein xmax and xmin are the maximum and minimum oil viscosities, respectively; injection cycles of the bank injection are repeated if an oil flow rate decreases to the pre-injection level.

EFFECT: higher displacement, coverage and recovery factors of the productive formation.

1 ex

FIELD: oil and gas industry.

SUBSTANCE: method involves dilution of salt rock with fresh or subsaline water by cyclic action on the formation, each of which includes pumping of a working agent to the saline oil formation through a well, closure of the well for the time of salt rock dilution, extraction of liquid from the formation through the same well. Cycles of action on the deposit are repeated till full coverage of the saline formation by action before opening of oil deposits contained in it and production of all the extracted oil deposits. Water pumping to the formation is performed at maximum possible constant bottom-hole pressure till reduction of the well water intake capacity by 2-8 times in comparison to its value at the pumping beginning, and extraction of liquid from the formation is performed at minimum possible constant bottom-hole pressure before the liquid with volume of at least 1.1-1.5 volumes of the fresh or subsaline water pumped to the formation earlier is removed to the surface.

EFFECT: increasing permeability of a saline formation throughout the area of its propagation, increasing productivity of production wells, increasing the coverage of the formation by action, volume of the removed oil deposits and acceleration of development rates.

4 cl, 1 tbl

FIELD: oil and gas industry.

SUBSTANCE: this invention refers to hydrocarbon production from a fractured reservoir. The method of hydrocarbon production from a fractured reservoir, which matrix is oil-wetted, includes at least one injector and producer, both interconnected to fractures and the matrix, consists of the following stages: a) injection primarily through the injector of a solution of surfactants, which increase viscosity and penetrate to the network of fractures interacting weakly with the matrix and creating a plug in situ in order to reduce significantly and selectively permeability of fractures and to facilitate passage of the solution at the stage b) to the matrix; b) injection secondarily through the injector of a solution of surfactants, which are capable to interact with the matrix thus preferably improving its oil-wetting and oil recovery, at that the above solution flows preferably through the matrix and upon the latent period of at least 24 hours; c) injection thirdly through the injector of water that leads to increase of surface tension, saturation of matrix, oil recovery and, upon solving of the above plug formed at the stage a) by oil, oil displacement to the producer. Invention is developed in dependent claims.

EFFECT: improvement of oil recovery.

17 cl, 3 dwg, 2 ex

FIELD: oil and gas industry.

SUBSTANCE: invention is related to the oil industry and can be used for the development and oil recovery improvement for inhomogeneous oil pools by waterflooding. In the development and oil recovery improvement method for the inhomogeneous oil pools including waterflooding with cyclic injection of a cross-linked alkali-polymer clayey quartz compound to the pool, wherein a water polymer solution cross-linked by chrome acetate is used as the polymer basis, at first the water solution of hydrolysed polyacrylamide (PAA) and chrome acetate cross-linker is injected, then the solution is flushed by water and a water suspension of a modified Lamco clay and quartz sand mixture is injected and then flushed by water, the above water solution comprises additionally caustic ash with the following concentration of the components, wt %: hydrolysed polyacrylamide PAA 0.01-0.30, chrome acetate 0.1-0.6, caustic ash 0.05-0.1, a ratio in the modified Lamco clay and quartz sand mixture.

EFFECT: improving oil recovery of the inhomogeneous and water-flooded pools at the late stage of development, reducing water cut of the product.

1 ex, 1 dwg

FIELD: oil-and-gas industry.

SUBSTANCE: proposed process comprises pre-flushing of the well with organic solvent. Then, organic solvent and film-forming anger are injected in the well. Film-forming agent represents 5-30% solution of boiler fuel in hydrocarbon solvent in amount of 0.5-2.5 m3/m of the bed perforated depth. Organic solvent buffer is used in amount of 3-6 m3 and aid solution in amount of 1-5 m3/m of perforated bed depth, injected fluids being injected thereafter in the bed.

EFFECT: higher efficiency of processing.

2 tbl, 4 ex

FIELD: oil-and-gas industry.

SUBSTANCE: invention relates to oil production, particularly, to from underground oil deposits. In compliance with this invention, at least one production well and one injection well can be used. Temperature distribution in the zone between said wells is analysed. In case temperature is distributed between said zones so that minimum temperature makes at least 20°C, maximum temperature does not exceed 320°C, while their difference makes at least 20°C, aqueous gel-forming preparations are injected via injection well that contain one or several chemical components. These preparations after injection in the deposit form gels under the effects of deposit temperature. Said preparations differ in type and/or concentration of chemical components. Chemical components and/or their concentration are selected to make gel-forming temperature and/or geol-forming time of the second and, if required, any other injected portion, differ from portions injected there before.

EFFECT: higher efficiency of oil extraction due to levelling of injectivity.

19 cl, 4 tbl, 7 dwg

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