A method for modifying fractures in tight oil reservoirs

Abstract

This invention discloses a method for fracturing fractures in tight oil reservoirs, belonging to the field of reservoir stimulation technology. This method induces test fracturing by determining the brittleness index and the number of perforations in the surrounding rock layers, thus obtaining the original natural fractures in the surrounding rock layers. By controlling the net pressure of the main fractures in these original natural fractures and rationally adjusting the dosage and injection method of slickwater, adhesive, and sealing agents, the complex natural fractures in the tight oil reservoir are extended and sealed over a large area. Finally, by heating the fracturing area, new fractures are opened, thereby opening reservoirs with different stresses and increasing the production of tight oil. This method effectively solves the problems of difficult fracturing initiation, simple fracture morphology, and low fracture complexity in tight oil reservoirs, thus improving the extraction efficiency of tight oil and having significant implications for enhancing the commercial value of tight oil.

Description

Technical Field

[0001] This invention belongs to the field of reservoir stimulation technology, and relates to a method for stimulating reservoir fractures, particularly a method for stimulating fractures in tight oil reservoirs. Background Technology

[0002] Tight oil is a term used in the petroleum industry to refer to oil located in tight reservoirs. It is mainly stored in unconventional reservoirs such as tight sandstone, marl, and dolomite, and possesses enormous exploration and development potential. As the remaining recoverable reserves of conventional oil resources decrease year by year, unconventional oil and gas resources, primarily tight oil and shale oil and gas, are gradually becoming the "main force" of new fossil energy supply globally, and the world's oil and gas extraction is entering the "tight oil era."

[0003] How to effectively utilize tight oil and fully tap its reservoir potential has become an urgent problem for those skilled in the art. Current technologies for tight oil extraction suffer from difficulties in initiating fractures and generating network or volumetric fractures, which limits the extraction of tight oil and consequently affects single-well production and ultimate recovery rate. Summary of the Invention

[0004] The purpose of this invention is to solve the problems in the prior art and provide a method for modifying fractures in tight oil reservoirs, so as to fully tap the reservoir potential of unconventional oil and gas resources such as tight oil, effectively utilize tight oil reservoirs, and improve the single-well production and ultimate recovery rate of tight oil.

[0005] To achieve the above objectives, the present invention employs the following technical solution:

[0006] A method for modifying fractures in tight oil reservoirs includes the following steps:

[0007] Based on the characteristics of the minerals in the rock layers surrounding the well section, the brittleness index of the rock layers surrounding the well section to be modified is evaluated.

[0008] The number of cluster perforations in the surrounding rock layers is determined based on the brittleness index of the well section.

[0009] Based on the number of perforations in the surrounding rock layers, induced fracturing tests were conducted on the surrounding rock layers.

[0010] After induced fracturing test, acid pretreatment is performed on the rock layer around the well section to open the original natural fractures in the rock layer around the well section.

[0011] Adjust the net pressure of the main fracture of the original natural fracture, control the length and opening of the original natural fracture in the surrounding rock layer of the well section, and inject slickwater and gel into the original natural fracture in stages.

[0012] Based on the number of perforations in the surrounding rock layers, sealing agents are injected in stages into the original natural fractures after the injection of slickwater and adhesive to seal the reservoir fractures.

[0013] After sealing is completed, the fracturing area is heated through the well section to seal the original natural fractures injected with sealing reagent, increase the bottom hole pressure, and open new fractures.

[0014] After a new fracture is opened, fracturing fluid and proppant are injected into reservoir segments that have not yet received fluid or have low fluid receipt through the new fracture to open up reservoirs with different stresses.

[0015] After reservoirs under different stresses are opened, acid treatment is performed on the original natural fractures after sealing to restore the permeability of the sealed reservoir, thereby completing the transformation of fractures in tight oil reservoirs.

[0016] Preferably, the method for evaluating the brittleness index of the rock layers surrounding the well section to be modified, based on the characteristics of the minerals in the surrounding rock layers, is as follows:

[0017] The results were obtained through a comprehensive evaluation using X-ray diffraction analysis, geophysical logging methods, and rock mechanics experiments.

[0018] Preferably, the method for determining the number of perforations in the surrounding rock layers based on the brittleness index of the surrounding rock layers is as follows:

[0019] When the brittleness index of the rock layer surrounding the well section is ≥50%, the number of cluster perforations in the rock layer surrounding the well section is determined to be 6 to 8 clusters.

[0020] When the brittleness index of the rock layer surrounding the well section is less than 50%, the number of cluster perforations in the rock layer surrounding the well section is determined to be 1 or 2 clusters.

[0021] Preferably, the acid pretreatment of the fractures generated after fracturing of the well section is performed using hydrochloric acid, with a dosage of 10m per perforation. 3 ~20m 3 .

[0022] Preferably, the method of adjusting the net pressure of the main fracture of the original natural fracture, controlling the length and opening of the original natural fracture in the surrounding rock layer, and alternately injecting slickwater and gel into the original natural fracture in stages is as follows:

[0023] When the original horizontal stress difference of the surrounding rock layer is less than or equal to 15% of the net pressure of the main fracture of the original natural fracture, the net pressure of the main fracture is adjusted to extend the length of the main fracture until the length of the main fracture reaches the designed target fracture length; when the original natural fracture is open, slickwater and gel are injected into the open original natural fracture in stages in an alternating manner.

[0024] When the original horizontal stress difference of the surrounding rock layers is greater than 15% of the net pressure of the main fracture of the original natural fracture, proppant is injected into the original natural fracture, so that the natural fracture opens with the support of the proppant. Slippery water and gel are then injected alternately into the opened original natural fracture in stages.

[0025] Preferably, after sealing is completed, the temperature for heating the fracturing area using the well section as a channel is 100℃~350℃.

[0026] Preferably, the plugging agent includes inorganic plugging agent and organic plugging agent, wherein the volume ratio of inorganic plugging agent to organic plugging agent is 1:(0.8-2).

[0027] Preferably, the inorganic plugging agent comprises the following raw material components by mass: 100 parts of calcined magnesia, 20 parts of magnesium chloride, 20 parts of ultrafine light calcium carbonate, 15 parts of silica powder, 10 parts of dispersant, 1 part of citric acid, 0.5 parts of phosphoric acid, 4 parts of water loss reducing agent, and 80 parts of water, wherein the calcined magnesia comprises MgO ≥ 93%, SiO2 ≤ 3.5%, and CaO ≤ 1.6%.

[0028] Preferably, the organic plugging agent comprises the following raw materials in parts by mass: 300 parts of liquefying agent phenol, 100 parts of polyethylene glycol, 10 parts of catalyst, 130 parts of fiber, 8 parts of benzoyl peroxide, 4 parts of tributyl phosphate, 120-600 parts of water, 1 part of calcium phosphate, 2 parts of polyvinyl alcohol, 7-9 parts of foaming agent, and 2-3 parts of calcium phosphate.

[0029] Preferably, the organic blocking agent is prepared as follows:

[0030] By mass, 300 parts of liquefying agent phenol, 100 parts of polyethylene glycol and 10 parts of catalyst are mixed evenly; 130 parts of fiber are added to the mixed solution and stirred evenly. During the stirring process, the mixture is heated to 140°C for reaction, and the reaction time is 50 min to 70 min to obtain the liquefied product.

[0031] Take 25 parts by volume of the liquefied product, add 8 parts of benzoyl peroxide and 4 parts of tributyl phosphate, and disperse evenly to obtain an oil phase mixed solution.

[0032] Take 120 parts of water, add 1 part of calcium phosphate and 2 parts of polyvinyl alcohol to the water and mix well. Adjust the pH of the mixed solution to 8-9. Add the above oil phase mixed solution to obtain a mixed solution. Heat the mixed solution to 90℃-95℃ to react and obtain primary particles.

[0033] Take 120 parts of the primary particles and mix them evenly with 450 parts of water. Add 7 to 9 parts of foaming agent and 2 to 3 parts of calcium phosphate. Stir at a constant temperature under an inert gas atmosphere to obtain foaming masterbatch, which is the organic blocking agent.

[0034] Compared with the prior art, the present invention has the following beneficial effects:

[0035] This invention provides a method for modifying fractures in tight oil reservoirs. The method involves inducing test fracturing by determining the brittleness index and the number of perforations in the surrounding rock layers to obtain the original natural fractures. By controlling the net pressure of the main fracture in the original natural fractures and rationally adjusting the dosage and injection method of slickwater, adhesive, and plugging agents, the complex natural fractures in the tight oil reservoir are extended and sealed over a large area. Finally, by heating the fracturing area, the opened original natural fractures are plugged, and the bottom hole pressure is increased to meet the conditions for new fracture opening. This forces fracturing fluid and proppant to enter non-fluidized or low-fluidized sections, opening reservoirs with different stresses and thus increasing the production of tight oil. This method effectively solves the problems of difficult fracturing initiation and low complexity of fractures in existing tight oil reservoirs, fully tapping the potential of tight oil reservoirs, achieving effective tight oil extraction, and enhancing the commercial value of tight oil. Attached Figure Description

[0036] To more clearly illustrate the technical solutions of the embodiments of the present invention, the accompanying drawings used in the embodiments will be briefly introduced below. It should be understood that the following drawings only show some embodiments of the present invention and should not be regarded as a limitation on the scope. For those skilled in the art, other related drawings can be obtained based on these drawings without creative effort.

[0037] Figure 1 This is a flowchart of the method for modifying fractures in tight oil reservoirs according to the present invention. Detailed Implementation

[0038] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. The components of the embodiments of the present invention described and shown in the accompanying drawings can generally be arranged and designed in various different configurations.

[0039] Therefore, the following detailed description of the embodiments of the invention provided in the accompanying drawings is not intended to limit the scope of the claimed invention, but merely to illustrate selected embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the invention without inventive effort are within the scope of protection of the invention.

[0040] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0041] In the description of the embodiments of the present invention, it should be noted that if terms such as "upper," "lower," "horizontal," or "inner" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, or the orientation or positional relationship commonly used when the product of the invention is in use, they are only for the convenience of describing the present invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of the present invention. Furthermore, terms such as "first" and "second" are only used to distinguish descriptions and should not be construed as indicating or implying relative importance.

[0042] Furthermore, the use of the term "horizontal" does not imply that the component must be absolutely horizontal, but rather that it can be slightly tilted. For example, "horizontal" simply means that its direction is more horizontal than "vertical," and does not mean that the structure must be completely horizontal, but can be slightly tilted.

[0043] In the description of the embodiments of the present invention, it should also be noted that, unless otherwise explicitly specified and limited, the terms "set," "install," "connect," and "link" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in the present invention according to the specific circumstances.

[0044] The present invention will now be described in further detail with reference to the accompanying drawings:

[0045] See Figure 1 This invention provides a method for modifying fractures in tight oil reservoirs, comprising the following steps:

[0046] Based on the characteristics of the minerals in the surrounding rock layers, the brittleness index of the rock layers surrounding the well section to be stimulated is evaluated. The content of brittle substances in the rock minerals is an important factor affecting the development of matrix porosity and microfractures, gas content, and fracturing stimulation methods. The lower the content of clay minerals in the rock layer, and the higher the content of brittle minerals such as quartz, feldspar, and calcite in silicate rocks and carbonate rocks, the stronger the rock brittleness, which is conducive to inducing fracture generation, forming a network of fractures, facilitating volumetric stimulation, and increasing the production of oil and gas in the surrounding rock layers. Based on the main characteristics of the rock layer minerals, the brittleness index of the rock layers surrounding the well section to be stimulated is obtained through a comprehensive evaluation using one or more of the following methods: X-ray diffraction analysis, geophysical logging methods, or rock mechanics experiments.

[0047] The number of perforations in the surrounding rock layer is determined based on its brittleness index. In production, fracturing of the surrounding rock layer is primarily achieved through fracturing tubing, which in turn completes fracturing via perforations in the wellbore. Therefore, the number of perforations must be determined according to the brittleness index of the rock layer. This invention addresses two scenarios: a brittleness index of 50% or higher and a brittleness index of less than 50%. For a brittleness index of 50% or higher, more perforations are required, typically 6-8 perforations, but this is not a limitation. For a brittleness index of less than 50%, fewer perforations are required, typically 1-2 perforations, but this is not a limitation.

[0048] Based on the number of perforations in the surrounding rock formations, induced fracturing tests are performed on the surrounding rock formations. Induced fracturing test technology is a specialized fracturing technique that involves a test fracturing operation with a certain scale of fluid injection before formal fracturing, but on a larger scale than conventional test fracturing. The purpose of induced fracturing test is to generate significant induced stress after the test fracturing pump is shut down and before the main fracturing begins. This can significantly reduce the horizontal stress difference during the main fracturing, thus improving the complexity of the main fracturing fractures. In this invention, induced fracturing test is performed in each well section, not only to understand reservoir characteristics but, more importantly, to generate induced stress and reduce the biaxial horizontal stress difference in the reservoir.

[0049] Following induced fracturing, acid pretreatment is performed on the surrounding rock formations to open the original natural fractures. During this pretreatment, conventional concentrations of industrial hydrochloric acid are typically used, with a dosage of 10–20 m per perforation. 3 Displacement 1-1.5m 3 / min.

[0050] To regulate the net pressure of the main fracture in the original natural fracture and control the length and opening of the original natural fracture in the surrounding rock layer, slickwater and gel are injected alternately into the original natural fracture in stages. When the net pressure of the main fracture in the original natural fracture is high, the main fracture is very prone to turning, which is very unfavorable for the extension of the main fracture over a large area. To address this issue, this invention proposes controlling the net pressure of the main fracture in the original natural fracture. That is, before the length of the main fracture reaches the design requirement, the net pressure is controlled so that it does not exceed the original horizontal stress difference, so that the main fracture will not turn and will continue to extend along the direction of the maximum horizontal principal stress. Once the length of the main fracture reaches the design requirement, the net pressure is then significantly increased. The specific operation is as follows: When the original horizontal stress difference of the surrounding rock layers is less than or equal to 15% of the net pressure of the main fracture of the original natural fracture, the net pressure of the main fracture is adjusted to extend the length of the main fracture until the length of the main fracture reaches the designed target fracture length; when the original natural fracture is open, slickwater and adhesive are injected into the open original natural fracture in stages; when the original horizontal stress difference of the surrounding rock layers is greater than 15% of the net pressure of the main fracture of the original natural fracture, proppant is injected into the original natural fracture, so that the natural fracture opens through the support of the proppant, and slickwater and adhesive are injected into the opened original natural fracture in stages.

[0051] For example, when the original horizontal stress difference in the rock layer is less than 15% of the net pressure of the main fracture (which is a natural crack), the net pressure of the main fracture must be controlled until the length of the main fracture reaches the expected target length. Then, the construction parameters should be adjusted to significantly increase the net pressure of the main fracture, thereby opening the micro-fracture system and significantly increasing the complexity of the crack. If the natural crack is an opening type, slickwater and adhesive should be injected alternately in multiple stages (at least 3-4 cycles). The low viscosity of the slickwater connects all the original natural cracks, while the high viscosity of the adhesive extends the main crack. The viscosity difference between the low-viscosity slickwater and the adhesive (generally required to be 3-5 times) creates a viscous fingering effect, allowing the slickwater to rapidly advance in a finger-like pattern to the leading edge of the adhesive, continuing to connect the original natural cracks. Through multiple alternating injection patterns, a large-scale extension of the main crack and a branch crack and micro-fracture system connected to the main crack throughout its length can be achieved, resulting in a significant increase in the volume of crack modification. When the original horizontal stress difference of the surrounding rock layers exceeds 15% of the net pressure of the main fracture of the original natural fracture, it is necessary to consider adding an in-fracture redirection agent to force the fracture to redirect once or multiple times. The difference is that this invention uses a combination of proppant methods to achieve in-fracture redirection, that is, injecting proppant into the fracture and using the proppant's supporting effect to open the fracture. Specifically, the first redirection can be achieved by mixing 70-140 mesh proppant with 40-70 mesh proppant in a certain proportion; the second redirection can be achieved by mixing 70-140 mesh proppant with 30-50 mesh proppant in a certain proportion; and the third redirection can be achieved by mixing 40-70 mesh proppant with 30-50 mesh proppant in a certain proportion. The application of proppant is not limited to these methods; the general principle is that the closer the redirection is to the fracture end, the higher the proportion of small-diameter proppant should be to prevent premature sand blockage.

[0052] Specifically, the original horizontal stress difference of the rock strata should be less than 15% of the net pressure of the main fracture, meaning the pressure difference between the two is greater than 5 MPa. It should be noted that if the net pressure of the main fracture is greater than the original horizontal stress difference, ideally within 5 MPa, a relatively ideal fracturing effect can be achieved.

[0053] In the above method, this invention is based on the understanding of fracture width and height under different brittle conditions: when the brittleness is good, the fracture toughness is low, and the extension rate of the fracture in the fracture length direction is much greater than the extension rate in the fracture width and height directions; that is, when the brittleness is good, the fracture length increases faster. Meanwhile, the fracture width and height basically do not increase or increase to a very limited extent. Here, it can be basically considered that fracture width * fracture length is proportional to the total fracturing energy. Therefore, when the rock layer has good brittleness, the number of clusters should be significantly increased. A higher number of clusters leads to greater interference from induced stress, and coupled with good brittleness, the induced stress propagates over a longer distance, which can promote the formation of large-area complex fractures.

[0054] Based on the number of perforations in the surrounding rock layers, sealing agents are injected in stages into the original natural fractures after the injection of slickwater and gel to seal the reservoir fractures. This application preferably uses both organic and inorganic sealing agents to seal the fractures, with a volume ratio of 1:(0.8-2). The inorganic sealing agent is used to achieve segmented fracturing of the surrounding rock layers and comprises the following raw material components by mass: 100 parts calcined magnesia, 20 parts magnesium chloride, 20 parts ultrafine light calcium carbonate, 15 parts silica powder, 10 parts dispersant, 1 part citric acid, 0.5 parts phosphoric acid, 4 parts fluid loss reducer, and 80 parts water. The calcined magnesia includes MgO ≥ 93%, SiO2 ≤ 3.5%, and CaO ≤ 1.6%. Calcined magnesia that is soluble in acid and has high strength is selected as one of the main components, giving the acid-soluble sealing agent high-strength temporary sealing and acid-soluble properties. Organic plugging agents used for permanent plugging include the following raw material components by mass: 300 parts liquefying agent phenol, 100 parts polyethylene glycol, 10 parts catalyst, 130 parts fiber, 8 parts benzoyl peroxide, 4 parts tributyl phosphate, 120-600 parts water, 1 part calcium phosphate, 2 parts polyvinyl alcohol, 7-9 parts foaming agent, and 2-3 parts calcium phosphate.

[0055] The preparation method of the plugging particles, i.e., organic plugging agents, is as follows:

[0056] Mix 300 parts of liquefying agent phenol, 100 parts of polyethylene glycol and 10 parts of catalyst evenly according to the mass ratio; add 130 parts of fiber to the mixed solution and stir evenly. During the stirring process, heat the mixture to 140°C for reaction. The reaction time is 50 min to 70 min to obtain the liquefied product.

[0057] Take 25 parts by volume of the liquefied product, add 8 parts of benzoyl peroxide and 4 parts of tributyl phosphate, and disperse evenly to obtain an oil phase mixed solution.

[0058] Take 120 parts of water, add 1 part of calcium phosphate and 2 parts of polyvinyl alcohol to the water and mix well. Adjust the pH of the mixed solution to 8-9. Add the above oil phase mixed solution to obtain a mixed solution. Heat the mixed solution to 90℃-95℃ to react and obtain primary particles.

[0059] Take 120 parts of the primary particles and mix them evenly with 450 parts of water. Add 7 to 9 parts of foaming agent and 2 to 3 parts of calcium phosphate. Stir at a constant temperature under an inert gas atmosphere to obtain foaming masterbatch, which is the organic blocking agent.

[0060] The specific operation is as follows: Select suitable fibers, for example, preferably poplar sawdust with a particle size greater than 100 mesh; in this invention, 300-400 mesh fibers are used. After obtaining fibers that meet the requirements (particle size and dryness, etc.), prepare liquefying agent phenol, polyethylene glycol-400, and catalyst concentrated sulfuric acid. Mix 300 parts of liquefying agent phenol, 100 parts of polyethylene glycol, and 10 parts of catalyst to obtain a mixture. Then, thoroughly stir the obtained mixture, and during the stirring process, add 130 parts of fiber to ensure thorough mixing with the mixture. Heat the mixture containing fiber while stirring, preferably to 140°C, for a reaction time of 50-70 minutes to ensure sufficient reaction between the mixture and the fiber, thereby obtaining a liquefied product. The mass fraction of polyethylene glycol is 5%, and the units of measurement for liquefying agent phenol, polyethylene glycol, catalyst, and fiber are all grams.

[0061] Then, take 25 parts of the above liquefied product, 8 parts of benzoyl peroxide, and 4 parts of tributyl phosphate for later use. Using the liquefied product as the base liquid, add benzoyl peroxide and tributyl phosphate (liquid) to the liquefied product. Since benzoyl peroxide is in powder form at room temperature, in order to ensure that the above mixture can be fully mixed and reacted, the present invention requires a dispersion operation after adding benzoyl peroxide and tributyl phosphate to the liquefied product to obtain an oil phase solution.

[0062] Using water as the base liquid, an aqueous solution is prepared by adding 1 part calcium phosphate and 2 parts polyvinyl alcohol to 120 parts water and stirring until homogeneous. After the aqueous solution is prepared, its pH needs to be adjusted to be between 8 and 9. In adjusting the pH of the aqueous solution, an alkaline solution is used, preferably sodium hydroxide, with a concentration of 40%. While stirring, an oil-phase solution is added to the aqueous solution to obtain an oil-water mixture, which is then heated to 90°C–95°C for reaction. The reaction time is 3–3.5 hours until complete, yielding primary particles.

[0063] Finally, prepare 120 parts of primary granules, 450 parts of water, 7-9 parts of foaming agent, and 2-3 parts of calcium phosphate. Add the primary granules to the water, followed by the foaming agent and calcium phosphate. After mixing the above components, stir at a constant temperature of 90℃-95℃ in an inert gas atmosphere to obtain foaming masterbatch. The reaction time is 10-11 hours to fully integrate the foaming agent with the primary granules, enabling the primary granules to foam and obtain the foaming masterbatch, i.e., the organic sealing agent, which foams upon heating.

[0064] After sealing, the fracturing area is heated through the well section: the purpose is to seal the original natural fractures injected with the sealing agent, increase the bottom hole pressure, and open new fractures. During the heating process, carbon dioxide in the natural magnesite is completely released, which causes magnesium oxide to form a dense mass to seal the reservoir fractures, increase the bottom hole pressure, and meet the conditions for opening new fractures.

[0065] After a new fracture is opened, fracturing fluid and proppant are injected through the new fracture into reservoir segments that have not yet received fluid or have low fluid reception, thereby opening up reservoirs with different stress levels.

[0066] After reservoirs under different stresses are opened, acid treatment is performed on the original natural fractures after sealing to restore the permeability of the sealed reservoir, thereby completing the transformation of fractures in tight oil reservoirs.

[0067] In summary, this invention provides a method for modifying fractures in tight oil reservoirs. By modifying the structure of the rock layers surrounding the well section, it enables large-area expansion and extension of fractures in tight oil reservoirs, effectively solving the problems of difficult fracture initiation, simple fracture morphology, and low fracture complexity in tight oil reservoirs.

[0068] The above are merely preferred embodiments of the present invention and are not intended to limit the present invention. Various modifications and variations can be made to the present invention by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.

Claims

1. A method of modifying a fracture in a tight reservoir, characterized by, The method comprises the following steps: based on the characteristics of the minerals in the rock layer around the well section, evaluating the brittleness index of the rock layer around the well section to be modified; determining the number of cluster perforations in the rock layer around the well section according to the brittleness index of the rock layer around the well section, specifically: when the brittleness index of the rock layer around the well section is greater than or equal to 50%, the number of cluster perforations in the rock layer around the well section is determined to be 6-8 clusters; when the brittleness index of the rock layer around the well section is less than 50%, the number of cluster perforations in the rock layer around the well section is determined to be 1 cluster or 2 clusters; induced testing and fracturing is performed on the rock layer around the well section according to the number of cluster perforations in the rock layer around the well section; after the induced testing and fracturing, the rock layer around the well section is subjected to acid pretreatment to open the original natural fractures in the rock layer around the well section; the net pressure of the main fracture of the original natural fracture is adjusted, the length and opening of the original natural fracture in the rock layer around the well section are controlled, and slickwater and gel are alternately injected into the original natural fracture in batches, specifically: when the original horizontal stress difference of the rock layer around the well section is less than or equal to 15% of the net pressure of the main fracture of the original natural fracture, the net pressure of the main fracture is adjusted to lengthen the length of the main fracture until the length of the main fracture reaches the designed target length; in the case that the original natural fracture is of the opening type, the slickwater and the gel are alternately injected into the opening original natural fracture in batches; when the original horizontal stress difference of the rock layer around the well section is greater than 15% of the net pressure of the main fracture of the original natural fracture, the proppant is injected into the original natural fracture to open the original natural fracture through the supporting action of the proppant, and the slickwater and the gel are alternately injected into the opening original natural fracture in batches; according to the number of cluster perforations in the rock layer around the well section, the sealing agent is put into the original natural fracture after the injection of the slickwater and the gel in batches to seal the reservoir fracture; after the sealing is completed, the fracturing area is heated with the well section as the channel to seal the original natural fracture after the injection of the sealing agent, increase the bottom hole pressure, and open a new fracture; after the new fracture is opened, the fracturing fluid and the proppant are injected into the reservoir layer section without fluid entry or with low fluid entry through the new fracture to open reservoirs with different stresses; after the reservoirs with different stresses are opened, the original natural fracture after the sealing is subjected to acidizing and deblocking to restore the permeability of the sealed reservoir, thereby completing the modification of the tight oil reservoir fracture.

2. The method of the compact reservoir fracture reformation according to claim 1, characterized in that, The method for evaluating the brittleness index of the rock layer around the well section to be modified based on the characteristics of the minerals in the rock layer around the well section comprises the following steps: The evaluation is obtained by comprehensively evaluating through X-ray diffraction analysis, geophysical logging method and rock mechanics experiment.

3. The method of the compact reservoir fracture reformation according to claim 1, characterized in that, The acid used in the process of acid pretreatment of the rock formation around the well section after the induced test fracturing is hydrochloric acid, and the amount of hydrochloric acid used for each cluster of cluster perforations is 10m 3 ~ 20m 3 .

4. The method of the compact reservoir fracture reformation according to claim 1, characterized in that, After the sealing is completed, the temperature for heating the fracturing area with the well section as the channel is 100-350℃.

5. The method of the compact reservoir fracture reformation according to any one of claims 1-4, characterized in that, The sealing agent comprises inorganic sealing agent and organic sealing agent, and the volume ratio of the inorganic sealing agent to the organic sealing agent is 1: (0.8-2).

6. The method of the compact reservoir fracture reformation of claim 5, wherein, The inorganic plugging reagent comprises the following components in parts by mass: dead-burned magnesite 100 parts, magnesium chloride 20 parts, superfine light calcium carbonate 20 parts, silicon powder 15 parts, dispersing agent 10 parts, citric acid 1 part, phosphoric acid 0.5 part, filtrate reducer 4 parts, and water 80 parts.

7. The method of the compact reservoir fracture reformation of claim 5, wherein, The organic plugging reagent comprises the following components in parts by mass: liquefier phenol 300 parts, polyethylene glycol 100 parts, catalyst 10 parts, fiber 130 parts, benzoyl peroxide 8 parts, tributyl phosphate 4 parts, water 120-600 parts, calcium phosphate 1 part, polyvinyl alcohol 2 parts, foaming agent 7-9 parts, and calcium phosphate 2-3 parts.

8. The method of the compact reservoir fracture reformation according to claim 7, characterized in that, The preparation method of the organic plugging reagent is as follows: In parts by mass, 300 parts of liquefier phenol, 100 parts of polyethylene glycol, and 10 parts of catalyst are mixed uniformly, and 130 parts of fiber is added into the mixed solution and stirred uniformly; during the stirring process, the mixed solution is heated to 140 DEG C for reaction, and the reaction time is 50-70 min to obtain a liquefied product; In volume, 25 parts of the liquefied product, 8 parts of benzoyl peroxide, and 4 parts of tributyl phosphate are taken and dispersed uniformly to obtain an oil phase mixed solution; 120 parts of water is taken, 1 part of calcium phosphate and 2 parts of polyvinyl alcohol are added into the water and mixed uniformly, and the pH value is adjusted to 8-9; the oil phase mixed solution is added into the mixture to obtain a mixture, and the mixture is heated to 90-95 DEG C for reaction to obtain primary particles; 120 parts of the primary particles and 450 parts of water are mixed uniformly, 7-9 parts of foaming agent and 2-3 parts of calcium phosphate are added, and constant temperature stirring is carried out in an inert gas atmosphere to obtain foaming master batch, which is the organic plugging reagent. The inorganic plugging reagent comprises the following components in parts by mass: dead-burned magnesite 100 parts, magnesium chloride 20 parts, superfine light calcium carbonate 20 parts, silicon powder 15 parts, dispersing agent 10 parts, citric acid 1 part, phosphoric acid 0.5 part, filtrate reducer 4 parts, and water 80 parts. The organic plugging reagent comprises the following components in parts by mass: liquefier phenol 300 parts, polyethylene glycol 100 parts, catalyst 10 parts, fiber 130 parts, benzoyl peroxide 8 parts, tributyl phosphate 4 parts, water 120-600 parts, calcium phosphate 1 part, polyvinyl alcohol 2 parts, foaming agent 7-9 parts, and calcium phosphate 2-3 parts. The preparation method of the organic plugging reagent is as follows: In parts by mass, 300 parts of liquefier phenol, 100 parts of polyethylene glycol, and 10 parts of catalyst are mixed uniformly, and 130 parts of fiber is added into the mixed solution and stirred uniformly; during the stirring process, the mixed solution is heated to 140 DEG C for reaction, and the reaction time is 50-70 min to obtain a liquefied product; In volume, 25 parts of the liquefied product, 8 parts of benzoyl peroxide, and 4 parts of tributyl phosphate are taken and dispersed uniformly to obtain an oil phase mixed solution; 120 parts of water is taken, 1 part of calcium phosphate and 2 parts of polyvinyl alcohol are added into the water and mixed uniformly, and the pH value is adjusted to 8-9; the oil phase mixed solution is added into the mixture to obtain a mixture, and the mixture is heated to 90-95 DEG C for reaction to obtain primary particles; 120 parts of the primary particles and 450 parts of water are mixed uniformly, 7-9 parts of foaming agent and 2-3 parts of calcium phosphate are added, and constant temperature stirring is carried out in an inert gas atmosphere to obtain foaming master batch, which is the organic plugging reagent.

Images