Sand fracturing method for achieving compact limestone reservoir dominant flow guide channel
By using multi-viscosity pre-flush fluid and multi-particle-size proppant-carrying methods, a complex fracture network is formed and proppant is filled in stages, which solves the problem of low gas production in tight limestone reservoirs and realizes efficient diversion channel construction and stable exploitation of oil and gas resources.
Patent Information
- Application Number
- CN202411619303.1
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Filing Date
- 2024-11-13
- Publication Date
- 2026-05-15
AI Technical Summary
Tight limestone reservoirs exhibit low gas production during acid fracturing and poor fracture conductivity, making them difficult to effectively stimulate.
The method of using multi-viscosity pre-fluid for fracture creation and multi-particle-size proppant carrying involves alternating injection of high, medium, and low viscosity pre-fluids to form a complex fracture network, and using proppant of different particle sizes to fill the fractures step by step, combined with low-viscosity displacement fluid to ensure proppant enters the reservoir.
It significantly improved the permeability and conductivity of tight limestone reservoirs, increased gas production during testing, constructed an efficient flow system, and solved the problems of poor adaptability and low production of acid fracturing technology in tight reservoirs.
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Figure CN122040104A_ABST
Abstract
Description
Technical Field
[0001] This invention belongs to the field of oil and gas field development and oil and gas reservoir stimulation, specifically relating to a sand fracturing method for realizing the advantageous flow channels in tight limestone reservoirs. Background Technology
[0002] Domestically and internationally, carbonate rocks possess abundant oil and gas resources, with limestone reservoirs being important gas-producing layers exhibiting excellent oil and gas storage capacity. During domestic oil and gas exploration, tight limestone reservoirs often show promising gas-bearing displays. After acidizing or acid fracturing, industrial gas flows can be obtained from tight limestone, but single-well production remains low. Addressing the issues of poor adaptability to acid fracturing and low test gas production in tight limestone reservoirs, the reservoir stimulation strategy has shifted from acid fracturing to proppant fracturing. Tight limestone reservoirs are characterized by high Young's modulus, high brittleness index, high fracturing pressure, high fracture extension pressure, high fracture surface tortuosity, and low fracture width, making proppant fracturing and improving fracture conductivity challenging. Therefore, this invention proposes a proppant fracturing method to achieve advantageous conductivity channels in tight limestone reservoirs, aiming to better solve the challenges of tight limestone reservoir stimulation. Summary of the Invention
[0003] To address the technical problems of low gas production and poor fracture conductivity in existing acid fracturing processes for tight limestone reservoirs, this invention provides a sand fracturing method for achieving superior conductivity channels in tight limestone reservoirs.
[0004] To achieve the above objectives, the present invention adopts the following technical solution: A method for proppant fracturing to achieve dominant flow channels in tight limestone reservoirs, characterized by comprising the following steps: Step S1: Multi-viscosity pre-flush liquid is used to create a crack. The main crack is created using high-viscosity pre-flush liquid, and then medium-viscosity and low-viscosity pre-flush liquid are used to continuously expand the main crack, create branch cracks and connect micro cracks by alternating injection according to the pre-flush liquid crack creation preset flow rate. Step S2: Carrying sand with multiple viscosities and particle sizes. This step is divided into three stages: S201 stage: First, medium viscosity sand-carrying fluid is used to carry micro-sized proppant, then low viscosity sand-carrying fluid is used to carry small-sized proppant. After the medium viscosity and low viscosity sand-carrying fluids carry proppant, they are injected alternately according to the first preset discharge rate of multi-viscosity sand-carrying fluid to fill and connect micro-cracks and some branch cracks. S202 stage: First, use high-viscosity sand-carrying fluid to carry small-diameter proppant, then use medium-viscosity sand-carrying fluid to carry medium-diameter proppant. After the high-viscosity and medium-viscosity sand-carrying fluids carry proppant, use alternating injection according to the second preset discharge rate of multi-viscosity sand-carrying fluid to fill the remaining branch cracks and part of the main cracks after the filling in S201 stage. S203 stage: First, use high-viscosity sand-carrying fluid to carry medium-sized proppant, then use medium-viscosity sand-carrying fluid to carry large-sized proppant. After the high-viscosity and medium-viscosity sand-carrying fluids carry proppant, use alternating injection according to the third preset discharge volume of multi-viscosity sand-carrying fluid to fill the remaining main cracks after the filling in S202 stage. Step S3: Low-viscosity displacement fluid displacement. The displacement process is carried out by using low-viscosity displacement fluid in an alternating injection manner according to the preset displacement fluid discharge rate, so as to push the sand-carrying fluid in step S2 into the reservoir.
[0005] In step S1, the viscosity of the high-viscosity pre-fluid is ≥90 mPa·s; the viscosity of the medium-viscosity pre-fluid is ≥60 mPa·s; and the viscosity of the low-viscosity pre-fluid is ≥30 mPa·s. The preset discharge rate of the pre-fluid for joint formation is 8–12 m³. 3 / min.
[0006] In step S1, the volume of high-viscosity pre-fluid accounts for 50% of the total volume of pre-fluid; the volume ratio of medium-viscosity pre-fluid to low-viscosity pre-fluid is 1:1; and the medium-viscosity pre-fluid and low-viscosity pre-fluid are injected alternately 5 times. In step S2, stage S201, the viscosity of the medium-viscosity sand-carrying fluid is ≥60 mPa·s; the viscosity of the low-viscosity sand-carrying fluid is ≥30 mPa·s; the volume ratio of the medium-viscosity sand-carrying fluid to the low-viscosity sand-carrying fluid is 1:1; the medium-viscosity and low-viscosity sand-carrying fluids are alternately injected at large volumes 3 times; the first preset discharge rate for multi-viscosity sand-carrying fluids of the medium-viscosity and low-viscosity sand-carrying fluids is 8-12 m³ / s. 3 / min.
[0007] In step S2, stage S201, the particle size proppant is 100-200 mesh ceramsite or quartz sand; the small particle size proppant is 70-140 mesh ceramsite or quartz sand.
[0008] In step S2, stage S202, the viscosity of the high-viscosity sand-carrying fluid is ≥90 mPa·s; the viscosity of the medium-viscosity sand-carrying fluid is ≥60 mPa·s; the volume ratio of the high-viscosity sand-carrying fluid to the medium-viscosity sand-carrying fluid is 1:1; the high-viscosity and medium-viscosity sand-carrying fluids are alternately injected at large volumes 3 times; the second preset discharge rate for multi-viscosity sand-carrying fluids of the high-viscosity and medium-viscosity sand-carrying fluids is 8-12 m³ / s. 3 / min. In step S2, stage S202, the small-sized proppant is 70-140 mesh ceramsite or quartz sand; the medium-sized proppant is 40-70 mesh ceramsite or quartz sand.
[0009] In step S2, stage S203, the viscosity of the high-viscosity sand-carrying fluid is ≥90 mPa·s, and the viscosity of the medium-viscosity sand-carrying fluid is ≥60 mPa·s; the volume ratio of the high-viscosity sand-carrying fluid to the medium-viscosity sand-carrying fluid is 1:1; the high-viscosity and medium-viscosity sand-carrying fluids are alternately injected at large volumes 3 times; the third preset discharge volume for multi-viscosity sand-carrying fluids of the high-viscosity and medium-viscosity sand-carrying fluids is 8-12 m³ / s. 3 / min.
[0010] In step S2, stage S203, the medium-sized proppant is 40-70 mesh ceramsite or quartz sand; the large-sized proppant is 20-40 mesh ceramsite or quartz sand.
[0011] In step S3, the viscosity of the low-viscosity displacement solution is 30 mPa·s, and the preset displacement rate of the low-viscosity displacement solution is 8–12 m³ / s. 3 / min.
[0012] Compared with the prior art, the present invention has the following beneficial effects: This invention discloses a proppant fracturing method for creating advantageous flow channels in tight limestone reservoirs. Step one involves using pre-flush fluids of varying viscosities and employing alternating high-volume injection techniques to efficiently form and expand a fracture network within the tight limestone reservoir. This network includes main fractures, branch fractures, and connecting microfractures, significantly improving reservoir permeability and providing more and wider channels for subsequent proppant transport and oil and gas flow. Step two, in its first stage, employs alternating injection of medium-to-low viscosity proppant-carrying fluids with proppant of different particle sizes, particularly micro-particle and small-particle proppant. This effectively fills fine fractures and connecting microfractures, enhancing the stability of the fracture network while minimizing reservoir damage, thus contributing to long-term oil and gas resource extraction efficiency. Step two, in its second stage, involves alternating injection of high-to-medium viscosity proppant-carrying fluids carrying small to medium-particle-size proppant, focusing on filling and reinforcing branch fractures and some main fractures, thus strengthening the internal structure of the fractured reservoir. The first step, using high- and medium-viscosity proppant-carrying fluids to carry medium to large-diameter proppant, significantly improves the permeability and conductivity of tight limestone reservoirs. The second step utilizes these fluids to reinforce and fill the main fractures, creating a more robust support structure that effectively maintains fracture openness, ensuring long-term conductivity stability and high reservoir production. The third step, through the efficient injection of low-viscosity displacement fluid, not only ensures the complete delivery of proppant and proppant into the reservoir, preventing proppant residue in the wellbore, but also reduces damage to the wellbore and maintains reservoir cleanliness, facilitating free flow of oil and gas and directly increasing test production. This multi-stage, meticulously designed proppant fracturing method significantly improves the permeability and conductivity of tight limestone reservoirs, overcoming the poor adaptability and low production of acid fracturing in tight reservoirs. It constructs an efficient flow system, providing advanced technology and practical solutions for the effective development of oil and gas resources.
[0013] Furthermore, the combination of high-viscosity, medium-viscosity, and low-viscosity pre-fracturing fluids, especially the use of high-viscosity polymer fracturing fluids, can effectively create and maintain the opening of the main fracture, while the alternating injection of medium- and low-viscosity pre-fracturing fluids promotes fracture propagation and branching. This volume ratio and injection rate setting ensures the efficient formation of the fracture network and improves the controllability and effectiveness of reservoir stimulation.
[0014] Furthermore, by precisely controlling the volume ratio of high, medium, and low viscosity pre-flush fluids and the number of alternating injections, refined management of fracture propagation was achieved. This not only ensured the stable propagation of the main fracture but also promoted the full connectivity of micro-fractures and branch fractures, thereby enhancing the connectivity and permeability of the reservoir.
[0015] Furthermore, in the S201 stage, the alternating injection strategy of medium- and low-viscosity proppant and proppant of different particle sizes helps to fill the cracks more evenly and deeply, especially to penetrate and reinforce the micro-cracks and small cracks, which is conducive to forming a good initial support structure and providing a good foundation for subsequent proppant carrying.
[0016] Furthermore, the selection of microparticle size and small particle size proppant ensures effective filling of micro fractures, reduces leakage, improves proppant embedding efficiency, opens up more microchannels for the reservoir, and enhances reservoir permeability and conductivity.
[0017] Furthermore, the combination of high and medium viscosity proppant-carrying fluids and corresponding particle size proppants used in the S202 stage further strengthened the support of branch fractures and main fractures, effectively preventing fracture closure and maintaining the high conductivity of the reservoir, thus laying a physical foundation for the smooth production of oil and gas.
[0018] Furthermore, the combined use of small and medium-sized proppant optimizes the internal support structure of fractures, balances the relationship between fracture support and permeability, and helps maintain long-term stable reservoir production.
[0019] Furthermore, by using multi-stage, multi-particle-size proppant to gradually fill cracks of different sizes, and by using proppant in stages from small to large, the uniformity and effectiveness of proppant within the cracks are ensured, crack closure is avoided, and the flow capacity of the cracks is improved, thereby increasing gas production.
[0020] Furthermore, in the S203 stage, a proppant fluid with a specific ratio and injection rate is used to strengthen the support of the main fracture. The addition of large-diameter proppant significantly improves the pressure-bearing capacity and stability of the fracture, creating favorable conditions for high-pressure oil and gas extraction.
[0021] Furthermore, the combination of medium- and large-particle-size proppant not only strengthens the fracture walls but also increases the flow space within the reservoir, making it particularly suitable for enhancing the main fractures and thus improving the final recovery rate.
[0022] Furthermore, the rapid, high-volume injection of low-viscosity displacement fluid ensures sufficient replacement and propulsion of the proppant and carrying fluid, reduces residues, protects the wellbore and reservoir, and provides an unobstructed flow path for subsequent oil and gas extraction, thereby effectively increasing the gas production of acid fracturing in tight limestone reservoirs.
[0023] Furthermore, the precise control of the injection parameters (such as velocity, volume ratio, and number of injections) of the pre-flush fluid and the sand-carrying fluid of different viscosities reduces physical and chemical damage to the reservoir, maintains the natural structure of the reservoir, and is conducive to maintaining long-term production capacity. Attached Figure Description
[0024] Figure 1 : Main process flow diagram of sand fracturing in the dominant flow channels of tight limestone reservoirs; Figure 2 : Schematic diagram of the state of fractures in a tight limestone reservoir during stage S1; Figure 3 : Schematic diagram of the different states of fractures in the three stages of step S2 within a tight limestone reservoir; Figure 4 : A schematic diagram of the different states of a tight limestone reservoir in the three stages of step S2. Detailed Implementation
[0025] To further understand the content of this invention, the invention will be described in detail below with reference to the accompanying drawings and specific embodiments. It should be understood that the embodiments are merely illustrative and not limiting of the invention.
[0026] The embodiments of the present invention will now be described in detail with reference to the accompanying drawings.
[0027] See Figure 1 , Figure 2 , Figure 3 and Figure 4 The proppant fracturing method for realizing the dominant flow channels in tight limestone reservoirs requires three steps: multi-viscosity pre-fracturing fluid fracturing, multi-viscosity multi-particle-size proppant carrying, and low-viscosity displacement fluid displacement; in step S1, when performing multi-viscosity pre-fracturing fluid fracturing, such as... Figure 2 As shown, the main fracture is first created by injecting a multi-viscosity pre-fluid from the wellhead, such as... Figure 2 As shown in (a), the multi-viscosity pre-flush fluid continues to be injected into the main fracture to create branch fractures, which further expand to connect with micro-fractures, such as... Figure 2 As shown in (b); step S2 is divided into three stages. Stage S201 involves multi-viscosity proppant carrying microparticles and small-particle proppant to mainly fill the branch cracks, such as... Figure 3As shown in (a); in stage S202, small-diameter and medium-diameter proppant are carried by a multi-viscosity proppant-carrying fluid to fill the remaining branch cracks and part of the main cracks after the first stage filling, as shown in (a). Figure 3 As shown in (b); in stage S203, medium-sized and large-sized proppant are carried by a multi-viscosity proppant-carrying fluid to fill the remaining main cracks after the second stage filling, as shown in (b). Figure 3 As shown in (c); in stage S201, the low-viscosity sand-carrying fluid carries proppant with a small particle size of 70-140 mesh, and the medium-viscosity sand-carrying fluid carries proppant with a particle size of 100-200 mesh, such as Figure 4 As shown in (a); in the S202 stage, the medium-viscosity sand-carrying fluid carries medium-sized proppant of 40–70 mesh, and the high-viscosity sand-carrying fluid carries small-sized proppant of 70–140 mesh, such as Figure 4 As shown in (b); in the S203 stage, the medium-viscosity sand-carrying fluid carries large-particle-size proppant of 20–40 mesh, and the high-viscosity sand-carrying fluid carries medium-particle-size proppant of 40–70 mesh, as shown in (b). Figure 4 As shown in (c), in the above three stages, the multi-viscosity sand-carrying liquid carries multi-particle-size proppant and is injected into the gap in three alternating stages, each stage being one round of alternating injection.
[0028] This embodiment provides a proppant fracturing method for realizing advantageous flow channels in tight limestone reservoirs. The specific implementation steps are as follows: This embodiment designs a precise proppant fracturing process for a tight limestone reservoir in a basin. The reservoir has a depth of 3140m, a porosity of 2.13%, and a matrix permeability of 0.70%. Fracturing operations are performed on this reservoir to efficiently develop oil and gas resources under these complex geological conditions. The specific implementation steps of this proppant fracturing method are as follows: multi-viscosity pre-fracturing fluid for fracture creation, multi-viscosity and multi-particle-size proppant transport, and low-viscosity displacement fluid for displacement.
[0029] Multi-viscosity pre-fluid for joint creation: First, fracturing fluid with a viscosity of 90 mPa·s was injected as a high-viscosity pre-flush fluid into a 150 m³ / h column. 3 Initial primary fractures were formed in the tight limestone reservoir; 60 mPa·s and 30 mPa·s fracturing fluids were used as medium-viscosity and low-viscosity pre-fracturing fluids, respectively, at a depth of 10 m... 3 The pre-fracturing fluid was injected into the main fracture using alternating pumps at a preset displacement of / min. Medium-viscosity pre-fracturing fluid formed branch fractures around the main fracture, while low-viscosity pre-fracturing fluid further expanded these branch fractures into connecting micro-fractures. During this fracturing operation, the total volume of high-viscosity, medium-viscosity, and low-viscosity pre-fracturing fluid injected alternately was 300m³. 3 The high-viscosity pre-fluid accounts for 50% of the total pre-fluid volume, while the volume ratio of medium-viscosity and low-viscosity pre-fluid is 1:1. The medium-viscosity and low-viscosity pre-fluids are injected alternately 5 times, with each injection consisting of 15m³ of medium-viscosity and low-viscosity pre-fluid.3 .
[0030] In this stage, high-viscosity pre-flush fluids exhibit minimal filtration loss in limestone reservoirs. Due to their high viscosity, they are less prone to forming branching fractures, which is beneficial for creating longer main fractures. Medium-viscosity pre-flush fluids exhibit moderate filtration loss in limestone reservoirs, which is conducive to the formation of branching fractures. Low-viscosity pre-flush fluids exhibit significant filtration loss in tight limestone reservoirs, which can further extend branching fractures, connect microfractures, and ultimately form a complex fracture network system, such as... Figure 2 (a) Figure 2 (b) and Figure 3 (a) Figure 3 (b) Figure 3 As shown in (c).
[0031] Multi-viscosity and multi-particle-size sand carrying: This step is divided into the following three stages: First, a fracturing fluid with a viscosity of 60 mPa·s is used as a medium-viscosity proppant to carry microparticles of proppant, with the proppant being 100–200 mesh quartz sand. Then, slickwater with a viscosity of 30 mPa·s is used as a low-viscosity proppant to carry small-particle proppant, with the small-particle proppant being 70–140 mesh quartz sand. The medium-viscosity and low-viscosity proppant are injected alternately at a first preset displacement of 10 m³ / s for multi-viscosity proppant carrying. 3 The medium-viscosity and low-viscosity sand-carrying fluids are pumped into the cracks formed during the crack-forming stage at a rate of / min to fill and connect micro-cracks and some branch cracks. Three stages of injection are required, with each stage consisting of an alternating injection. The total volume of medium-viscosity and low-viscosity sand-carrying fluids throughout the entire construction process is 180m³. 3 The volume ratio of medium-viscosity and low-viscosity sand-carrying fluid is 1:1, and the single injection volume of both medium-viscosity and low-viscosity sand-carrying fluids is 30m³. 3 The total volume of quartz sand is 12.6 m³. 3 The amount of quartz sand injected in a single operation is 2.1m³. 3 The concentration of 100-200 mesh quartz sand and 70-140 mesh quartz sand is 10%; the total volume of medium-viscosity and low-viscosity sand-carrying fluid injected in a single operation is 60m³. 3 The medium-viscosity and low-viscosity sand-carrying fluids need to be injected alternately three times, with a total injection volume of 4.2 m³ for each stage of quartz sand injection. 3 .
[0032] Then, a 90 mPa·s fracturing fluid was used as a high-viscosity proppant-carrying fluid to carry small-diameter proppant, which consisted of 70–140 mesh quartz sand. A 60 mPa·s polymer fracturing fluid was then used as a medium-viscosity proppant-carrying fluid to carry medium-diameter proppant, which consisted of 40–70 mesh quartz sand. The high-viscosity and medium-viscosity proppant-carrying fluids were injected alternately at a second preset displacement of 10 m³ / s for multi-viscosity proppant carrying. 3The medium-viscosity proppant is injected into the cracks at a rate of / min to fill branch cracks and part of the main cracks; the medium-viscosity proppant enters the high-viscosity proppant to form viscous fingering, so that the medium-sized proppant is located in the middle of the small-sized proppant, forming a dominant flow channel composed of medium-sized proppant in the middle of the branch cracks. The total volume of high-viscosity and medium-viscosity proppant during the entire construction process is 180m³. 3 The high-viscosity and medium-viscosity sand-carrying fluids require three injection stages, with each stage consisting of an alternating injection. The volume ratio of the high-viscosity to the medium-viscosity sand-carrying fluids is 1:1, and the single injection volume for both high-viscosity and medium-viscosity sand-carrying fluids is 30m³. 3 The total volume of injected quartz sand is 18m³. 3 The total volume of 70-140 mesh quartz sand and 40-70 mesh quartz sand injected in a single batch is 6m³. 3 The concentration of 70-140 mesh quartz sand and 40-70 mesh quartz sand injected in a single application is 10%. Finally, a polymer fracturing fluid with a viscosity of 90 mPa·s was used as a high-viscosity proppant-carrying fluid to carry medium-sized proppant, which consisted of 40–70 mesh quartz sand. Then, a polymer fracturing fluid with a viscosity of 60 mPa·s was used as a medium-viscosity proppant-carrying fluid to carry large-sized proppant, which consisted of 20–40 mesh quartz sand. This was done using an alternating injection method with a third preset displacement of 10 m³ / s for multi-viscosity proppant carrying. 3 The medium-viscosity proppant is injected into the crack at a rate of / min to fill the main crack. The medium-viscosity proppant enters the high-viscosity proppant, creating viscosity and allowing the large-diameter proppant particles to be positioned in the middle of the medium-diameter particles, forming a dominant flow channel composed of large-diameter proppant particles in the middle of the main crack. The total volume of the high-viscosity and medium-viscosity proppant during the entire construction process is 180m³. 3 The high-viscosity and medium-viscosity sand-carrying fluids need to be injected alternately three times, with each stage constituting one alternating injection. The volume ratio of the high-viscosity and medium-viscosity sand-carrying fluids is 1:1, and the single injection volume of both high-viscosity and medium-viscosity sand-carrying fluids is 30m³. 3 The total volume of quartz sand injected using both high-viscosity and medium-viscosity sand-carrying fluids is 18 m³. 3 The concentration of both 40-70 mesh and 20-40 mesh quartz sand injected is 10%, and each injection carries 3 m of both types of quartz sand. 3 .
[0033] The above three stages sequentially fill the connecting micro-fractures and some branch fractures, branch fractures and some main fractures, and the main fracture to ensure that the fractures in the tight limestone reservoir are fully filled.
[0034] Low-viscosity displacement fluid displacement stage: Low-viscosity fracturing fluid of 30 mPa·s was used as the displacement fluid, with a 10m... 3 / min displacement pumped into 25m 3 The sand-carrying fluid from the above stages is then pushed into the reservoir to complete the displacement operation.
[0035] Furthermore, it should be understood that although this specification describes embodiments, not every embodiment contains only one independent technical solution. This narrative style is merely for clarity. Those skilled in the art should consider the specification as a whole, and the technical solutions in each embodiment can be appropriately combined to form other embodiments that can be understood by those skilled in the art. The above content is only for illustrating the technical concept of the present invention and should not be construed as limiting the scope of protection of the present invention. Any modifications made based on the technical concept proposed in this invention shall fall within the scope of protection of the claims of this invention.
Claims
1. A method for proppant fracturing to achieve dominant flow channels in tight limestone reservoirs, characterized in that, Includes the following steps: Step S1: Multi-viscosity pre-flush liquid is used to create a crack. The main crack is created using high-viscosity pre-flush liquid, and then medium-viscosity and low-viscosity pre-flush liquid are used to continuously expand the main crack, create branch cracks and connect micro cracks by alternating injection according to the pre-flush liquid crack creation preset flow rate. Step S2: Carrying sand with multiple viscosities and particle sizes. This step is divided into three stages: S201 stage: First, medium viscosity sand-carrying fluid is used to carry micro-sized proppant, then low viscosity sand-carrying fluid is used to carry small-sized proppant. After the medium viscosity and low viscosity sand-carrying fluids carry proppant, they are injected alternately according to the first preset discharge rate of multi-viscosity sand-carrying fluid to fill and connect micro-cracks and some branch cracks. S202 stage: First, use high-viscosity sand-carrying fluid to carry small-diameter proppant, then use medium-viscosity sand-carrying fluid to carry medium-diameter proppant. After the high-viscosity and medium-viscosity sand-carrying fluids carry proppant, use alternating injection according to the second preset discharge rate of multi-viscosity sand-carrying fluid to fill the remaining branch cracks and part of the main cracks after the filling in S201 stage. S203 stage: First, use high-viscosity sand-carrying fluid to carry medium-sized proppant, then use medium-viscosity sand-carrying fluid to carry large-sized proppant. After the high-viscosity and medium-viscosity sand-carrying fluids carry proppant, use alternating injection according to the third preset discharge volume of multi-viscosity sand-carrying fluid to fill the remaining main cracks after the filling in S202 stage. Step S3: Low-viscosity displacement fluid displacement. The displacement process is carried out by using low-viscosity displacement fluid in an alternating injection manner according to the preset displacement fluid discharge rate, so as to push the sand-carrying fluid in step S2 into the reservoir.
2. The method for proppant fracturing to achieve dominant flow channels in tight limestone reservoirs according to claim 1, characterized in that, In step S1, the viscosity of the high-viscosity pre-treatment liquid is ≥90 mPa·s; the viscosity of the medium-viscosity pre-treatment liquid is ≥60 mPa·s; and the viscosity of the low-viscosity pre-treatment liquid is ≥30 mPa·s. The preset discharge volume of the pre-treatment liquid for joint formation is 8–12 m³. 3 / min.
3. The method for proppant fracturing to realize advantageous flow channels in tight limestone reservoirs according to claim 2, characterized in that, In step S1, the volume of high-viscosity pre-fluid accounts for 50% of the total volume of pre-fluid; the volume ratio of medium-viscosity pre-fluid to low-viscosity pre-fluid is 1:1; and the number of times medium-viscosity pre-fluid and low-viscosity pre-fluid are injected alternately is 3 to 5.
4. The method for proppant fracturing to realize advantageous flow channels in tight limestone reservoirs according to claim 1, characterized in that, In step S201 of the above step S2, the viscosity of the medium-viscosity sand-carrying liquid is ≥60 mPa·s; the viscosity of the low-viscosity sand-carrying liquid is ≥30 mPa·s; the volume ratio of the medium-viscosity sand-carrying liquid to the low-viscosity sand-carrying liquid is 1:1; the number of alternating injections of the medium-viscosity and low-viscosity sand-carrying liquids at large discharge volumes is 3 to 5 times; and the first preset discharge volume for multi-viscosity sand-carrying liquids of the medium-viscosity and low-viscosity sand-carrying liquids is 8 to 12 m³. 3 / min.
5. The method for proppant fracturing to realize advantageous flow channels in tight limestone reservoirs according to claim 4, characterized in that, In step S2, stage S201, the particle size proppant is 100-200 mesh ceramsite or quartz sand; the small particle size proppant is 70-140 mesh ceramsite or quartz sand.
6. The method for proppant fracturing to achieve dominant flow channels in tight limestone reservoirs according to claim 1, characterized in that, In step S2, stage S202, the viscosity of the high-viscosity sand-carrying liquid is ≥90 mPa·s; the viscosity of the medium-viscosity sand-carrying liquid is ≥60 mPa·s; the volume ratio of the high-viscosity sand-carrying liquid to the medium-viscosity sand-carrying liquid is 1:1; the high-viscosity sand-carrying liquid and the medium-viscosity sand-carrying liquid are alternately injected at large volumes 3 to 5 times; and the second preset discharge volume for multi-viscosity sand-carrying liquids of the high-viscosity sand-carrying liquid and the medium-viscosity sand-carrying liquid is 8 to 12 m³ / s. 3 / min.
7. The method for proppant fracturing to realize advantageous flow channels in tight limestone reservoirs according to claim 6, characterized in that, In step S2, stage S202, the small-particle-size proppant is 70-140 mesh ceramsite or quartz sand; the medium-particle-size proppant is 40-70 mesh ceramsite or quartz sand.
8. The method for proppant fracturing to realize dominant flow channels in tight limestone reservoirs according to claim 1, characterized in that, In step S2, stage S203, the viscosity of the high-viscosity sand-carrying liquid is ≥90 mPa·s, and the viscosity of the medium-viscosity sand-carrying liquid is ≥60 mPa·s; the volume ratio of the high-viscosity sand-carrying liquid to the medium-viscosity sand-carrying liquid is 1:1; the high-viscosity sand-carrying liquid and the medium-viscosity sand-carrying liquid are alternately injected at large volumes 3 to 5 times; the third preset discharge volume for multi-viscosity sand-carrying liquids of the high-viscosity sand-carrying liquid and the medium-viscosity sand-carrying liquid is 8 to 12 m³ / s. 3 / min.
9. The method for proppant fracturing to realize dominant flow channels in tight limestone reservoirs according to claim 8, characterized in that, In step S2, stage S203, the medium-sized proppant is 40-70 mesh ceramsite or quartz sand; the large-sized proppant is 20-40 mesh ceramsite or quartz sand.
10. The method for proppant fracturing to realize dominant flow channels in tight limestone reservoirs according to claim 1, characterized in that, In step S3, the displacement fluid is a low-viscosity fracturing fluid with a displacement rate of 30 mPa·s and a displacement rate of 8–12 m³ / s. 3 / min.