Ultra-deep reservoir fracturing transformation method

Abstract

The invention provides a fracturing transformation method for an ultra-deep reservoir. The method comprises the steps that before a target ultra-deep reservoir is fractured, acid liquor is injected into the target ultra-deep reservoir, and soaking is conducted after the acid liquor is injected; the target ultra-deep reservoir is fractured for the first time, and a main fracture is formed; a temporary plugging agent is injected into the target ultra-deep reservoir, and the temporary plugging agent is used for plugging the front end of a main fracture formed in the target ultra-deep reservoir; solid capsule acid is injected into the target ultra-deep reservoir with the front end of the main fracture in the temporary plugging state, the solid capsule acid enters the main fracture formed in the target ultra-deep reservoir, and soaking is conducted after the solid capsule acid reaches the preset position; in the soaking process, the capsule dressing of the solid capsule acid is degraded under the temperature and pressure conditions in the target ultra-deep reservoir, and the acid core is released; and the target ultra-deep reservoir with the front end of the main fracture in the temporary plugging state and the solid capsule acid acidification completed is fractured for the second time, and a secondary fracture is formed.

Description

Technical Field

[0001] This invention belongs to the field of deep fracturing technology for unconventional oil and gas reservoirs, specifically relating to a method for fracturing and stimulating ultra-deep reservoirs. Background Technology

[0002] Ultra-deep reservoirs are a crucial component of oil and gas resources; however, their exploitation rate is low. Ultra-deep reservoirs are located at great depths, with some Cambrian ultra-deep reservoirs reaching depths of 10,029-10,777 meters, making drilling extremely challenging. Due to the extremely complex geological conditions, high temperature and pressure, dense reservoir structure, and low natural productivity of ultra-deep reservoirs, hydraulic fracturing is necessary to create multiple fractures or activate natural fractures to form a fracture network, thereby increasing single-well productivity and achieving economical and efficient exploitation.

[0003] Ultra-deep reservoirs, due to their great depth and high temperature and pressure, present challenges during fracturing, including limited increases in flow rate and fluid viscosity, difficulty in increasing net pressure within fractures, and challenges in temporary plugging within fractures. Furthermore, natural fractures in ultra-deep reservoirs are often filled with calcite and other materials, resulting in high cementation strength and activation pressure, making it difficult to form complex fracture networks during fracturing. This severely restricts the economical and effective development of oil and gas resources in ultra-deep reservoirs. Existing hydraulic fracturing methods for ultra-deep reservoir fracturing struggle to increase net pressure and have low fracture activation efficiency. Existing acid fracturing methods for ultra-deep reservoir fracturing result in rapid acid release and fast high-temperature acid-rock reaction (the reaction rate at 180℃ is nearly 30 times faster than at 120℃). The high-temperature acid acts primarily near the wellbore, failing to etch and reduce the cementation strength of distant natural fractures, resulting in low natural fracture opening.

[0004] In conclusion, new fracturing methods still need to be studied to achieve effective fracturing of ultra-deep reservoirs and create conditions for increased production in ultra-deep reservoirs. Summary of the Invention

[0005] The purpose of this invention is to provide a technical solution that enables effective fracturing of ultra-deep reservoirs, thereby creating conditions for increased production in ultra-deep reservoirs.

[0006] To achieve the above objectives, the present invention provides the following technical solution.

[0007] This invention provides a method for fracturing and stimulating ultra-deep reservoirs (reservoirs with a burial depth of not less than 6500m), wherein the method includes:

[0008] Acidizing step: Before fracturing the target ultra-deep reservoir, acid is injected into the target ultra-deep reservoir, and the well is shut in after the acid injection;

[0009] First fracturing step: After acidizing, the target ultra-deep reservoir is subjected to the first fracturing to form the main fracture;

[0010] Temporary plugging agent injection procedure: Inject temporary plugging agent into the target ultra-deep reservoir after the first fracturing to seal the front end of the main fracture that has already formed in the target ultra-deep reservoir;

[0011] Solid capsule acidizing steps: Solid capsule acid is injected into the target ultra-deep reservoir in a temporarily plugged state at the front end of the main fracture. The solid capsule acid enters the main fracture that has already formed in the target ultra-deep reservoir. After the solid capsule acid reaches the predetermined position, the well is shut in. During the shut-in process, the capsule of the solid capsule acid degrades under the temperature and pressure conditions in the target ultra-deep reservoir, and the acid core is released. After the acid core is released, it reacts with the fracture wall rock of the main fracture, thereby achieving targeted damage to the fracture wall of the main fracture.

[0012] The second fracturing step involves performing a second fracturing operation on the target ultradeep reservoir where the front end of the main fracture is in a temporary plugging state and has already undergone solid capsule acidification, thereby forming secondary fractures.

[0013] The ultra-deep reservoir fracturing stimulation method provided by this invention is a fracturing method that combines acidizing, temporary plugging, and solid capsule acidizing. It forms a complex fracture network in ultra-deep reservoirs through a combined force-chemical approach, thereby better stimulating the reservoirs. In this ultra-deep reservoir fracturing stimulation method, temporary plugging and targeted solid capsule acidizing are performed on the basis of acidizing and primary fracturing, followed by secondary fracturing, achieving combined force-chemical fracturing of the ultra-deep reservoir. Acidizing damages rock strength, reducing rock fracture pressure; the self-viscosity enhancement (temperature-controlled viscosity increase) of the fracturing fluid within the fracture, combined with the synergistic effect of temporary plugging, increases the net pressure within the fracture; targeted acidizing damage using capsule acid reduces the fracture initiation pressure within the fracture, achieving multi-scale acid fracturing and creating a complex fracture network; the combined force-chemical action activates natural weak surfaces, creating new fractures, connecting natural fractures, and increasing the complexity of the fracture network, enabling the development of ultra-deep reservoir oil and gas resources to reach industrial-scale oil and gas flow.

[0014] According to a specific embodiment of the ultra-deep reservoir fracturing stimulation method provided by the present invention, preferably, in the acidizing step, the acid solution used is determined according to the mineral composition of the target ultra-deep reservoir and the temperature and pressure conditions of the target ultra-deep reservoir.

[0015] More preferably, the ultra-deep reservoir fracturing stimulation method further includes:

[0016] Obtain core samples from the target ultra-deep reservoir;

[0017] The mineral composition of the core samples from the target ultra-deep reservoir was determined using X-ray diffraction and scanning electron microscopy with energy dispersive spectroscopy.

[0018] By utilizing the mineral composition of the core sample from the target ultra-deep reservoir and the temperature and pressure conditions of the target ultra-deep reservoir, the acid solution used in the chemical treatment step is selected.

[0019] In one specific embodiment, the acid used in the acidification step includes at least one of formic acid (HCOOH), acetic acid (CH3COOH), hydrochloric acid, and emulsified acid.

[0020] According to a specific embodiment of the ultra-deep reservoir fracturing stimulation method provided by the present invention, preferably, in the acidizing step, the acid injection volume is 60-100m³. 3 (e.g., 80m) 3 ).

[0021] According to a specific embodiment of the ultra-deep reservoir fracturing and stimulation method provided by the present invention, preferably, the well-steaming time in the acidizing step is 2h-8h.

[0022] In one specific embodiment, during the acidizing step, the pumping pressure of the acid solution is lower than the formation fracturing pressure of the target ultra-deep reservoir.

[0023] Rock fracturing pressure refers to the minimum pressure that the bottom of the well must withstand when the formation fractures and cracks form. Exceeding this pressure will allow drilling fluid or fracturing fluid to enter the formation fractures. It is usually estimated through field well testing.

[0024] According to a specific embodiment of the ultra-deep reservoir fracturing and stimulation method provided by the present invention, preferably, the first fracturing is carried out by hydraulic fracturing.

[0025] More preferably, the first fracturing of the target ultra-deep reservoir includes: sequentially pumping pre-fracturing fluid and high-viscosity fracturing fluid into the target ultra-deep reservoir to form the main fracture; wherein the viscosity of the pre-fracturing fluid is 40-80 mPa·s (e.g., 50 mPa·s), and the viscosity of the high-viscosity fracturing fluid is 200-2000 mPa·s;

[0026] The fracturing fluid and high-viscosity fracturing fluid used in the first fracturing process can be selected from existing fracturing fluids and high-viscosity fracturing fluids, but are not limited to, depending on the formation conditions. For example, slickwater can be used as the fracturing fluid. For example, at least one of guar gum fracturing fluid, viscoelastic surfactant fracturing fluid (VES), and synthetic polymer fracturing fluid can be used as the high-viscosity fracturing fluid, which is usually improved by cross-linking.

[0027] In the first fracturing process, the pumping pressure of the pre-fracturing fluid can be determined according to actual needs, but is not limited to this. In the preferred technical solution, the pumping pressure of the pre-fracturing fluid in the first fracturing process exceeds the estimated formation fracturing pressure of the target ultra-deep reservoir by 4-8 MPa.

[0028] The injection volume of the pre-fracturing fluid during the first fracturing process can be determined, but is not limited to, based on actual needs. In the preferred technical solution, the injection volume of the pre-fracturing fluid during the first fracturing process is 350-450 mg / L. 3 ;

[0029] For example, slickwater is selected as the pre-fracturing fluid, and the pumping flow rate is 7m³. 3 / min, viscosity 50mPa·s;

[0030] In the first fracturing process, the pumping pressure of the high-viscosity fracturing fluid can be determined according to actual needs, but is not limited to meeting the requirements for forming the main fracture. In the preferred technical solution, the pumping pressure of the high-viscosity fracturing fluid in the first fracturing process exceeds the estimated formation fracturing pressure of the target ultra-deep reservoir by 4-8 MPa.

[0031] The injection volume of high-viscosity fracturing fluid during the first fracturing process can be determined, but is not limited to, based on actual needs, as long as it is sufficient to form the main fracture. In the preferred technical solution, the injection volume of high-viscosity fracturing fluid during the first fracturing process is 100-200 mg / L. 3 .

[0032] According to a specific embodiment of the ultra-deep reservoir fracturing stimulation method provided by the present invention, preferably, the second fracturing is carried out by hydraulic fracturing.

[0033] More preferably, the second fracturing of the target ultra-deep reservoir includes:

[0034] Pre-fracturing fluid and high-viscosity fracturing fluid are pumped into the target ultra-deep reservoir to form secondary fractures; the viscosity of the pre-fracturing fluid is 40-80 mPa·s; the viscosity of the high-viscosity fracturing fluid is 200-2000 mPa·s.

[0035] Then the proppant is injected along with the sand-carrying fluid;

[0036] Finally, inject the displacement solution;

[0037] The fracturing fluid used in the second fracturing process can be selected from the existing fracturing fluids and fracturing fluids, but not limited to, based on the formation conditions. For example, the fracturing fluid can be slickwater fracturing fluid, and the high-viscosity fracturing fluid can be at least one of guar gum fracturing fluid, viscoelastic surfactant fracturing fluid (VES), and clean fracturing fluid.

[0038] In the second fracturing process, the pumping pressure of the pre-fracturing fluid can be determined according to actual needs, but is not limited to meeting the requirements for the formation of secondary fractures. In the preferred technical solution, the pumping pressure of the pre-fracturing fluid in the second fracturing process exceeds the formation fracturing pressure of the target ultra-deep reservoir by 5-12 MPa.

[0039] The injection volume of the pre-fracturing fluid during the second fracturing process can be determined, but is not limited to, based on actual needs, as long as it is sufficient to form secondary fractures. In the preferred technical solution, the injection volume of the pre-fracturing fluid during the second fracturing process is 120-180 mg / L. 3 ;

[0040] In the second fracturing process, the pumping pressure of the high-viscosity fracturing fluid can be determined according to actual needs, but is not limited to meeting the requirements for the formation of secondary fractures. In the preferred technical solution, the pumping pressure of the high-viscosity fracturing fluid in the second fracturing process exceeds the formation fracturing pressure of the target ultra-deep reservoir by 5-12 MPa.

[0041] The injection volume of high-viscosity fracturing fluid during the second fracturing process can be determined, but is not limited to, based on actual needs, as long as it is sufficient to meet the requirements for the formation of secondary fractures. In the preferred technical solution, the injection volume of high-viscosity fracturing fluid during the second fracturing process is 150-200 mg / L. 3 ;

[0042] The proppant-carrying fluid used in the second fracturing process can be selected from existing proppant-carrying fluids, but is not limited to, depending on the formation conditions. For example, at least one of cross-linked guar gum proppant-carrying fluid and thickened polymer proppant-carrying fluid can be used.

[0043] In the second fracturing process, the pumping pressure of the proppant-carrying fluid can be determined according to actual needs, but is not limited to the requirement of carrying the proppant into the fracture formed by fracturing. In the preferred technical solution, the pumping pressure of the proppant-carrying fluid in the second fracturing process exceeds the rock fracture pressure at this time, for example, 110-120 MPa. As the proppant-carrying fluid is injected, the pressure stabilizes or decreases, indicating that the fracture is expanding.

[0044] The amount of proppant injected during the second fracturing process can be determined, but is not limited to, based on actual needs, as long as it is sufficient to carry enough proppant to support the fractures formed by the fracturing. In a preferred embodiment, the amount of proppant injected during the second fracturing process is 20-80 mg / m³. 3 The injection volume of the sand-carrying fluid is 200-300m³. 3 ;

[0045] Among them, the proppant may be, but is not limited to, high-strength ceramsite of 30 / 50 mesh to 70 / 140 mesh;

[0046] The displacement fluid used in the second fracturing process can be selected from existing displacement fluids, but is not limited to, based on formation conditions. For example, the displacement fluid used in the second fracturing process can be at least one of clean brine displacement fluid and linear gel displacement fluid.

[0047] In the second fracturing process, the pumping pressure of the displacement fluid can be determined according to actual needs, but is not limited to the requirement that it can replace the proppant-carrying fluid to the target location. In the preferred technical solution, the pumping pressure of the displacement fluid in the second fracturing process exceeds the rock fracturing pressure at this time, for example, 110-140 MPa.

[0048] The amount of displacement fluid injected during the second fracturing process can be determined, but is not limited to, based on actual needs, as long as it is sufficient to displace the proppant-carrying fluid to the target location. In the preferred technical solution, the amount of displacement fluid injected during the second fracturing process is 40-60 mg / m³. 3 .

[0049] According to a specific embodiment of the ultra-deep reservoir fracturing stimulation method provided by the present invention, the temporary plugging agent can be selected from existing temporary plugging agents according to the formation conditions. The selected temporary plugging agent can withstand the formation temperature and pressure and can meet the requirement of sealing the fracture front to increase the net pressure inside the fracture. For example, at least one of the following can be used: biodegradable polymer temporary plugging agent, temperature-controlled expansion particle temporary plugging agent, and fiber-particle composite temporary plugging agent.

[0050] According to a specific embodiment of the ultra-deep reservoir fracturing method provided by the present invention, preferably, the temporary plugging agent is injected into the target ultra-deep reservoir using liquid-carried injection.

[0051] More preferably, the liquid may be, but is not limited to, fracturing fluid.

[0052] According to a specific embodiment of the ultra-deep reservoir fracturing method provided by the present invention, preferably, during the injection of temporary plugging agent into the target ultra-deep reservoir, the injection pressure is lower than the formation fracturing pressure of the target ultra-deep reservoir.

[0053] According to a specific embodiment of the ultra-deep reservoir fracturing stimulation method provided by the present invention, the injection volume of the temporary plugging agent can be determined, but is not limited to, based on actual needs, as long as it meets the requirements for sealing the front end of the main fracture. In a preferred embodiment, the injection volume of the temporary plugging agent is 2-8m³. 3 (e.g., 6m) 3 ).

[0054] In one specific embodiment, the injection volume of the temporary plugging agent is 6m. 3 The displacement is 1.5m. 3 / min, the temporary plugging agent reaches the front end of the crack.

[0055] According to a specific embodiment of the ultra-deep reservoir fracturing method provided by the present invention, preferably, the solid encapsulated acid is selected from solid encapsulated acids whose coating can be degraded under the temperature and pressure conditions of the target ultra-deep reservoir and whose core can be acid-etched into the target ultra-deep reservoir rock.

[0056] More preferably, the ultra-deep reservoir fracturing stimulation method further includes:

[0057] Obtain core samples from the target ultra-deep reservoir;

[0058] The mineral composition of the core samples from the target ultra-deep reservoir was determined using X-ray diffraction and scanning electron microscopy with energy dispersive spectroscopy.

[0059] Based on the mineral composition of the core sample from the target ultra-deep reservoir and the temperature and pressure conditions of the target ultra-deep reservoir, solid encapsulated acid was selected;

[0060] In one specific embodiment, the solid encapsulated acid is selected from at least one of polymer-coated encapsulated acid, temperature-sensitive microsphere-encapsulated acid, and inorganic shell-layered sustained-release acid.

[0061] In a specific embodiment of the ultra-deep reservoir fracturing method provided by the present invention, preferably, solid encapsulated acid is injected into the target ultra-deep reservoir using liquid-carried methods.

[0062] More preferably, the liquid may be, but is not limited to, fracturing fluid;

[0063] More preferably, injecting solid encapsulated acid into the target ultra-deep reservoir where the main fracture tip is in a temporarily plugged state includes:

[0064] Solid capsule acid is injected using a sand-carrying fluid pump; wherein the viscosity of the sand-carrying fluid is 200-2000 mPa·s;

[0065] Then, the displacement fluid is pumped in to push the solid encapsulated acid into the fracture, preventing the solid encapsulated acid from flowing back into the wellbore;

[0066] For example, the solid capsule acid has a particle size of 20 mesh, and the mass concentration of the solid capsule acid does not exceed 5% based on the mass of the sand-carrying liquid as 100%.

[0067] For example, with 5.5m 3 A dilute gel displacement fluid with a viscosity of 45 mPa·s is pumped at a flow rate of / min to push the solid encapsulated acid into the fracture, preventing the solid encapsulated acid from flowing back into the wellbore. In a specific embodiment of the ultra-deep reservoir fracturing method provided by this invention, preferably, during the injection of solid encapsulated acid into the target ultra-deep reservoir, the injection pressure is lower than the formation fracturing pressure of the target ultra-deep reservoir.

[0068] According to a specific embodiment of the ultra-deep reservoir fracturing stimulation method provided by the present invention, preferably, the injection volume of solid encapsulated acid is 30-50m³. 3 .

[0069] In a specific embodiment of the ultra-deep reservoir fracturing method provided by the present invention, preferably, the solid encapsulated acid reaching the predetermined position means that the solid encapsulated acid reaches the temporary plugging zone at the front end of the main fracture.

[0070] The ultra-deep reservoir fracturing method provided by this invention is a combined implementation scheme of acidizing, temporary plugging, solid capsule acidizing, and fracturing. It achieves multi-dimensional acidizing effect through multi-stage acid injection, reduces the fracturing pressure of ultra-deep rocks, and generates a large number of secondary fractures in ultra-deep reservoirs through mechanical-chemical combination in conjunction with temporary plugging and multiple fracturing. This results in a complex interweaving of natural and artificial fractures, forming a complex fracture network, expanding the effective stimulation volume, increasing oil and gas production, and improving recovery rate. Attached Figure Description

[0071] Figure 1 This is a schematic diagram of combined hydraulic and chemical fracturing. Detailed Implementation

[0072] 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, not all, of the embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the protection scope of the present invention.

[0073] Example 1

[0074] This implementation provides a fracturing stimulation method for ultra-deep reservoirs.

[0075] This ultra-deep reservoir fracturing method is used to fracture and stimulate ultra-deep reservoirs at a burial depth of 8000m and a formation fracturing pressure of 140MPa-180MPa. The method includes:

[0076] Step S1: Determine the reservoir mineral composition and select appropriate acid, fracturing fluid, temporary plugging agent, and solid encapsulated acid, specifically including:

[0077] 1.1 Optimal acid solution system:

[0078] First, mineralogical analysis was performed on the core samples of the target reservoir, including X-ray diffraction (XRD) analysis, thin section identification, scanning electron microscopy (SEM) energy dispersive spectroscopy, fluorescence spectroscopy, and whole-rock chemical composition analysis. Through detection, the content and proportion of carbonate minerals (calcite, dolomite), siliceous minerals (quartz, feldspar), and clay minerals (illite, kaolinite, montmorillonite) in the core samples of the target reservoir were obtained.

[0079] Based on the content and proportion of carbonate minerals and siliceous minerals in the core sample of the target reservoir, the appropriate acid system is selected. Among them, when carbonate minerals are the main components, the hydrochloric acid (HCl) slow-release acid system, or slow-release acid, emulsified acid is preferred. When there is a high proportion of dolomite or high-temperature reservoir, the hydrochloric acid-formic acid mixed acid or organic acid system is preferred. When the content of siliceous minerals or clay minerals is high, the composite acid (mud acid) of hydrofluoric acid (HF) and hydrochloric acid, or chelated acid system can be used.

[0080] During the acid determination process, based on the formation temperature of 160℃-180℃, methanol, corrosion inhibitors, pressure, and wellbore material are added to formulate corresponding corrosion inhibitors, iron ion stabilizers, clay stabilizers, and surfactants to achieve efficient and controllable use of the acid.

[0081] In this embodiment, the acid solution used is composed of: 9wt% hydrochloric acid + 3wt% acetic acid + 1.5wt% hydrofluoric acid + 2wt% Clay-Web clay stabilizer + 3wt% corrosion inhibitor + 1wt% Gasperm 1100 drainage aid + 2wt% Gel-StaL iron ion stabilizer + 0.3wt% Armohib CI-213 drag reducer + 5wt% ALSTAFLOC WS waterproofing agent + 1wt% BASF demulsifier + the balance being water.

[0082] 1.2 Optimization of Temporary Plugging Agent System

[0083] Based on formation temperature, pressure, fracture width, and permeability characteristics, determine the required temperature resistance, pressure resistance, and particle size range of the temporary plugging agent. When the formation temperature is >150℃, high-temperature resistant polymer-based or inorganic particulate temporary plugging agents should be selected to ensure the pressure resistance, high-temperature resistance, and decomposition ability of the temporary plugging agent.

[0084] Plugging Capacity Test: In this embodiment, a Biovert temporary plugging system composed of HT-828 solid resin particles, polyester fiber, and magnesium and its alloy powder was used. The resulting temporary plug was tested to ensure it could withstand a pressure of 150 MPa for 2 hours at 200 degrees Celsius. This plugging system meets the target plugging strength. Reversibility Evaluation: A degradation experiment was conducted on the plugging material under high-temperature conditions, ensuring degradation within 4 hours at 140°C, thus avoiding permanent damage to the reservoir.

[0085] 1.3. Using an acid-rock reaction system, core samples from multiple target ultra-deep reservoirs were acidified with nitric acid, lactic acid and citric acid, solid alkyl sulfonic acid, citric acid, amino sulfonic acid, and organic phosphoric acid to obtain acid-etched deep core samples.

[0086] 1.4. Using a high-temperature and high-pressure triaxial rock mechanics testing machine (GCTS-RTR-1500), triaxial compression tests were conducted on the core samples before and after acid etching in step 1.3 under confining pressure of 50-120 MPa, pore pressure of 30-60 MPa, and temperature of 120-200℃ (120℃, 150℃, 180℃, 200℃). The stress-strain curves of the rock under high-temperature mechanical-chemical damage were obtained, and the rock mechanics parameters after the high-temperature acid rock reaction were obtained.

[0087] 1.5. Based on the experimental results of step 1.4, select solid encapsulated acid that is compatible with the formation conditions of the target ultra-deep reservoir.

[0088] In this embodiment, the core of the solid capsule acid is made of solid alkyl sulfonic acid, and the capsule coating is made of PBMA solid resin.

[0089] 1.6 Optimization of Fracturing Fluid System

[0090] The fracturing fluid system is determined based on the formation temperature, pressure, fracture width, and permeability characteristics.

[0091] Step S2, the acidification step, specifically includes:

[0092] Before fracturing the target ultra-deep reservoir, acid is injected into the target ultra-deep reservoir, and the well is then shut in after the acid injection.

[0093] The acid injection volume is 50m. 3 The well was kept closed for 4 hours, and the acid injection pressure was 40 MPa.

[0094] Step S3, the first fracturing step, specifically includes:

[0095] After acidizing, pre-fracturing fluid and high-viscosity fracturing fluid are sequentially pumped into the target ultra-deep reservoir to form the main fracture, thus achieving the first fracturing of the target ultra-deep reservoir.

[0096] The pre-fracturing fluid used is FR-66 slickwater fracturing fluid with a viscosity of 200 mPa·s, a pumping pressure of 120 MPa, and an injection volume of 300 m³ / s. 3 ;

[0097] The high-viscosity fracturing fluid used was 0.35% guar gum fracturing fluid with a viscosity of 300 mPa·s, a pumping pressure of 120 MPa, and an injection rate of 200 m³ / s. 3 .

[0098] Step S4, the temporary plugging agent injection step, specifically includes:

[0099] Temporary plugging agent was injected into the target ultra-deep reservoir after the first fracturing. The temporary plugging agent was first injected at a pressure of 140 MPa and the pressure change was monitored. The injection rate of the temporary plugging agent was 1.5 m³ / min, and 6 m³ was pumped in (the pressure was stabilized at 129 MPa for 5 minutes). The pumping continued until the pressure rose to a level with pressure fluctuations of < ±2 MPa and stabilized for 20 minutes, indicating that the temporary plugging agent had sealed the front end of the main fracture that had already formed in the target ultra-deep reservoir.

[0100] Step S5, the acidification step of solid capsules, specifically includes:

[0101] For the target ultra-deep reservoir where the front end of the main fracture is in a temporary plugging state, solid encapsulated acid is pumped in using a proppant-carrying fluid; then, displacement fluid is pumped in to push the solid encapsulated acid into the fracture interior to prevent the solid encapsulated acid from flowing back into the wellbore.

[0102] After the solid encapsulated acid enters the main fracture that has already formed in the target ultra-deep reservoir and reaches the predetermined position, the well is shut off.

[0103] During the well-sealing process, the solid encapsulated acid degrades under the temperature and pressure conditions in the target ultra-deep reservoir, and the acid core is released. After the acid core is released, it reacts with the rock on the fracture wall of the main fracture, thereby achieving targeted damage to the fracture wall of the main fracture.

[0104] The sand-carrying solution consists of 0.6 wt% polyacrylamide solution with a molecular weight of 15 million; the solid encapsulated acid has a mass concentration of 5% based on 100% of the sand-carrying solution; the pumping rate of the sand-carrying solution is 7 m³ / min; and the injection rate of the solid encapsulated acid is 60 m³ / min. 3 ;

[0105] The displacement solution was a 0.1 wt% polyacrylamide solution with a molecular weight of 15 million; the viscosity of the displacement solution was 45 mPa·s; the displacement rate was 5.5 m³ / min and the injection volume was 40 m³ / min. 3 .

[0106] The solid encapsulated acid is 20 mesh (more than 3 times the diameter of the temporary plugging agent particles) to ensure it does not migrate to the fracture end. The temporary plugging agent seals the front end of the main fracture, while the solid encapsulated acid is located closer to the wellbore. During the well-clogging process, the temperature and pressure of the target ultra-deep reservoir dissolve the capsule of the solid encapsulated acid (the outer shell melts at 220℃ / 170MPa). After the capsule dissolves, the acid core is slowly released (clogging time 6 hours). After well opening, it is released at a rate of 0.1m... 3 / h low-speed backflow prevents capsule residue from clogging the pores.

[0107] Step S6, the second fracturing step, specifically includes:

[0108] In the target ultradeep reservoir, which is in a temporary plugged state at the front end of the main fracture and has completed solid capsule acidification, pre-fracturing fluid and high-viscosity fracturing fluid are pumped in sequence to form secondary fractures.

[0109] Then the proppant is injected along with the sand-carrying fluid;

[0110] Finally, displacement fluid is injected to complete the second fracturing of the target ultra-deep reservoir.

[0111] The fracturing fluid used is slickwater fracturing fluid with a viscosity of 60 mPa·s. The pumping pressure of the fracturing fluid is 125 MPa, and the injection volume of the fracturing fluid is 180 m³ / s. 3 ;

[0112] The high-viscosity fracturing fluid used was 0.35% guar gum fracturing fluid with a viscosity of 300 mPa·s, a pumping pressure of 120 MPa, and an injection rate of 45 m³ / s. 3 .

[0113] The sand-carrying fluid is a 0.6wt% crosslinked polyacrylamide solution with a molecular weight of 15 million, with a ground viscosity of 2000 mPa·s. The pumping pressure of the sand-carrying fluid is 140 MPa, the injection volume of the proppant is 55 m³, and the injection volume of the sand-carrying fluid is 300 m³. 3 .

[0114] The displacement solution was selected as a 0.1 wt% dilute polyacrylamide solution with a molecular weight of 15 million and a viscosity of 50 mPa·s. The pumping pressure of the displacement solution was 110 MPa, and the injection volume of the displacement solution was 45 m³ / s. 3 .

[0115] This embodiment employs a combined mechanical-chemical fracturing method for ultra-deep reservoirs (such as...). Figure 1 As shown in the figure, under the combined effect of force and chemical reaction, a large number of secondary fractures are generated, which are more complex than traditional temporary plugging fracturing.

[0116] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. A method of ultra-deep reservoir fracturing modification, wherein, The method comprises: an acidizing step: before fracturing the target ultra-deep reservoir, injecting acid liquid into the target ultra-deep reservoir, and conducting a soak after the acid liquid is injected; a first fracturing step: after the acidizing, fracturing the target ultra-deep reservoir for the first time to form a main fracture; a temporary plugging agent injection step: injecting a temporary plugging agent into the target ultra-deep reservoir that has completed the first fracturing, and using the temporary plugging agent to plug the front end of the main fracture formed in the target ultra-deep reservoir; a solid capsule acid acidizing step: injecting a solid capsule acid into the target ultra-deep reservoir where the front end of the main fracture is in a temporary plugging state, the solid capsule acid entering the main fracture formed in the target ultra-deep reservoir, and conducting a soak after the solid capsule acid reaches a predetermined position; during the soak, the capsule coating of the solid capsule acid degrades under the temperature and pressure conditions in the target ultra-deep reservoir, the acid core is released, and the acid core reacts with the fracture wall rock of the main fracture after being released, thereby achieving point damage to the fracture wall of the main fracture; a second fracturing step: fracturing the target ultra-deep reservoir where the front end of the main fracture is in a temporary plugging state and has completed the solid capsule acid acidizing for the second time to form a secondary fracture.

2. The ultra-deep reservoir fracturing modification method according to claim 1, wherein, In the acidizing step, the acid liquid used is determined according to the mineral composition of the target ultra-deep reservoir and the temperature and pressure conditions of the target ultra-deep reservoir. Preferably, in the acidizing step, the acid liquid used comprises at least one of formic acid, acetic acid, hydrochloric acid, and emulsified acid.

3. The ultra-deep reservoir fracturing reconstruction method according to claim 1, wherein The acid injection amount in the acidizing step is 60-100 m 3 ; In the acidizing step, the soak time is 2-8 hours. In the acidizing step, the pumping pressure of the acid liquid is lower than the formation breakdown pressure of the target ultra-deep reservoir.

4. The ultra-deep reservoir fracturing reformation method according to claim 1, wherein, The first fracturing is performed in a hydraulic fracturing manner. Preferably, the first fracturing of the target ultra-deep reservoir comprises: pumping a pre-pad fracturing fluid and a high-viscosity fracturing fluid into the target ultra-deep reservoir to form a main fracture; wherein the viscosity of the pre-pad fracturing fluid is 40-80 mPa·s, and the viscosity of the high-viscosity fracturing fluid is 200-2000 mPa·s. More preferably, the pumping pressure of the pre-pad fracturing fluid during the first fracturing exceeds the formation breakdown pressure of the target ultra-deep reservoir by 4-8 MPa. More preferably, the pumping pressure of the high-viscosity fracturing fluid during the first fracturing exceeds the formation breakdown pressure of the target ultra-deep reservoir by 4-8 MPa.

5. The ultra-deep reservoir fracturing reformation method according to claim 1, wherein, The second fracturing is performed in a hydraulic fracturing manner. Preferably, the second fracturing of the target ultra-deep reservoir comprises: pumping a pre-pad fracturing fluid and a high-viscosity fracturing fluid into the target ultra-deep reservoir to form a secondary fracture; wherein the viscosity of the pre-pad fracturing fluid is 40-80 mPa·s, and the viscosity of the high-viscosity fracturing fluid is 200-2000 mPa·s; further injecting proppants with the injected sand-carrying fluid; finally injecting a displacement fluid; More preferably, the pumping pressure of the pre-pad fracturing fluid during the second fracturing exceeds the formation breakdown pressure of the target ultra-deep reservoir by 5-12 MPa. More preferably, the pumping pressure of the high-viscosity fracturing fluid during the second fracturing exceeds the formation breakdown pressure of the target ultra-deep reservoir by 5-12 MPa.

6. The ultra-deep reservoir fracturing reformation method according to claim 1, wherein, During the injection of the temporary plugging agent into the target ultra-deep reservoir, the injection pressure is lower than the formation breakdown pressure of the target ultra-deep reservoir.

7. The ultra-deep reservoir fracturing reformation method according to claim 1, wherein, The solid capsule acid is selected from capsule coating capable of degrading under the temperature and pressure conditions of the target ultra-deep reservoir and acid core capable of acid-etching the rock of the target ultra-deep reservoir. Preferably, the solid capsule acid is at least one of polymer-coated capsule acid, temperature-sensitive microsphere-encapsulated acid, and inorganic shell layer-sustained-release acid.

8. The ultra-deep reservoir fracturing reformation method according to claim 1, wherein, The solid capsule acid is injected into the target ultra-deep reservoir by using a liquid carrier.

9. The ultra-deep reservoir fracturing reformation method according to claim 1, wherein, During the injection of the solid capsule acid into the target ultra-deep reservoir, the injection pressure is lower than the formation breakdown pressure of the target ultra-deep reservoir.

10. The method for fracturing reconstruction of an ultra-deep reservoir according to claim 1, wherein, The injection amount of the solid capsule acid is 30-50 m 3 ; The solid capsule acid reaching the predetermined position refers to the solid capsule acid reaching the temporary plugging zone of the front end of the main fracture to temporarily plug the front end of the main fracture.

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