A method for hydraulic fracturing complex fractures in tight sandstone reservoirs

Abstract

This invention relates to the field of downhole operations in oil and gas fields, and particularly to a method for fracturing complex fractures in tight sandstone reservoirs, aiming to solve the problem of significant formation damage in existing fracturing methods. This method combines supercritical carbon dioxide fracturing with conventional hydraulic fracturing. Utilizing the superior fluidity and diffusivity of supercritical carbon dioxide, it further increases the complexity of fractures beyond the long and highly conductive fractures created by conventional hydraulic fracturing. Simultaneously, the weakly acidic environment provided by carbon dioxide inhibits clay expansion, reduces reservoir damage, and ultimately improves the stimulation effect of tight sandstone reservoirs.

Description

Technical Field

[0001] This invention relates to the field of downhole operations in oil and gas fields, and in particular to a method for fracturing complex fractures in tight sandstone reservoirs. Background Technology

[0002] my country's recoverable reserves of tight sandstone gas have reached 10 trillion cubic meters, accounting for 40% of the country's total proven natural gas reserves, making it an important area for increasing my country's natural gas reserves and production.

[0003] Tight sandstone gas reservoirs in my country are generally characterized by underdeveloped natural fractures, strong heterogeneity, high fracturing pressure, and large horizontal stress differences, making it difficult to form the complex network of fractures seen in shale oil and gas reservoirs. Current stimulation strategies primarily involve medium-displacement, small-scale operations, high-viscosity fluids, and large-particle-size ceramic aggregates to create long fractures and high-conductivity fractures. However, with deepening development, the common reality in my country's large gas fields is a continuous decline in reservoir quality and a year-on-year decrease in gas testing results. How to increase the degree of fracture on the basis of creating long fractures to further improve the stimulation effect and achieve stable and increased gas well production is a major concern for the petroleum industry.

[0004] Patent CN104747158A provides a method for the stimulation of high-muddy sandstone, employing pre-treatment of the formation with acid to reduce construction pressure and increase the success rate of fracturing in high-muddy sandstone, thereby improving the stimulation effect. This method can reduce the construction difficulty of high-muddy reservoirs and increase the success rate, but it cannot increase the complexity of fractures. Patent CN114607341A provides a temporary plugging and redirection fracturing method. This method involves adding a temperature-sensitive phase change plugging agent, setting it to be liquid within a target area and solid outside the target area. A displacement fluid is used to deliver the liquid plugging agent to the designated location, where it solidifies upon reaching the target temperature, thus achieving temporary plugging and redirection. Compared to conventional solid plugging agents, this method reaches a greater depth, achieving targeted sealing and fracture initiation, which is more conducive to the formation of complex fractures and improves the stimulation effect. While the temporary plugging and redirection process can increase the complexity of fractures, the plugging material injected into the formation may not completely degrade, potentially causing significant damage to the formation. Summary of the Invention

[0005] To improve the complexity of fractures in tight sandstone reservoirs while reducing reservoir damage, this invention proposes a fracturing method for complex fractures in tight sandstone reservoirs. This method can effectively improve the stimulation effect of tight sandstone reservoirs.

[0006] To solve the above-mentioned technical problems, the technical solution provided by the present invention is as follows:

[0007] The present invention provides a method for hydraulic fracturing complex fractures in tight sandstone reservoirs, comprising:

[0008] (1) Pump the pre-filled fluid into the target layer;

[0009] (2) Pump liquid carbon dioxide into the target layer;

[0010] (3) Injecting bio-glue fracturing fluid systems of different viscosities sequentially into the target layer. This step is divided into three stages, including:

[0011] First stage: Pump low-viscosity bio-glue fracturing fluid mixed with 70 / 140 mesh ceramsite into the target layer; wherein, the viscosity of the low-viscosity bio-glue fracturing fluid is 8-15 mPa·s, the 70 / 140 mesh ceramsite is added in a slug-type manner, and the sand ratio is 3%-7%.

[0012] Second stage: Pumping medium-high viscosity bio-glue fracturing fluid mixed with 40 / 70 mesh ceramsite into the target layer; wherein, the viscosity of the medium-high viscosity bio-glue fracturing fluid is 60-80 mPa·s, the 40 / 70 mesh ceramsite is added continuously, and the sand ratio is 7%-18%.

[0013] The third stage involves pumping high-viscosity bio-glue fracturing fluid mixed with 20 / 40 mesh ceramsite into the target layer. The viscosity of the high-viscosity bio-glue fracturing fluid is 90-110 mPa·s, and the 20 / 40 mesh ceramsite is added continuously with a sand ratio of 19-33%.

[0014] (4) Inject medium-viscosity bio-glue fracturing fluid with a viscosity of 30-50 mPa·s and water into the target layer in sequence for replacement construction.

[0015] Furthermore,

[0016] In step (1), the pre-fluid is a high-viscosity bio-glue fracturing fluid, which is prepared by mixing 1.9-2.2% polymer thickener, 0.1-0.15% nano-displacement agent, 0.3-0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 90-110 mPa·s, and the 170s... -1 The viscosity under high-speed shear is >80 mPa·s.

[0017] Furthermore,

[0018] In step (1), the pre-fluid volume is 10%-20% of the total construction fluid volume, and the pump discharge rate is 6-10m³. 3 / min.

[0019] Furthermore,

[0020] In step (2), the injection volume of liquid carbon dioxide is 50-100 m³. 3 The injection displacement is 3-4m³. 3 / min.

[0021] Furthermore,

[0022] In step (3), the low-viscosity bio-adhesive fracturing fluid is prepared by mixing 0.3-0.5% polymer thickener, 0.1-0.15% nano-displacement agent, 0.3-0.5% high-efficiency anti-swelling agent and the balance water, with a base fluid viscosity of 8-15 mPa·s.

[0023] Furthermore,

[0024] In step (3), the medium-high viscosity bio-adhesive fracturing fluid is prepared by mixing 1.3-1.6% polymer thickener, 0.1-0.15% nano-displacement agent, 0.3-0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 60-80 mPa·s, and the 170s... -1 The viscosity under high-speed shear is >50 mPa·s.

[0025] Furthermore,

[0026] In step (3), the high-viscosity bio-adhesive fracturing fluid is prepared by mixing 1.9–2.2% polymer thickener, 0.1–0.15% nano-displacement agent, 0.3–0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 90–110 mPa·s, and the 170s... -1 The viscosity under high-speed shear is >80 mPa·s.

[0027] Furthermore,

[0028] In step (3), the amount of 70 / 140 mesh ceramsite used is 5%-10%, the amount of 40 / 70 mesh ceramsite used is 10%-20%, and the amount of 20 / 40 mesh ceramsite used is 70%-85%.

[0029] Furthermore,

[0030] In step (3), the pumping rate of fracturing fluid in the three stages is 6-10 m³ / h. 3 / min.

[0031] Furthermore,

[0032] In step (4), the medium-viscosity bio-adhesive fracturing fluid is prepared by mixing 0.8–1.2% polymer thickener, 0.1–0.15% nano-displacement agent, 0.3–0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 30–50 mPa·s, and the 170s... -1 Viscosity >20 mPa·s under high-speed shear;

[0033] In step (4), the displacement volume of the medium-viscosity bio-adhesive is 0.6 times the wellbore volume, the displacement volume of the clean water is 0.5 times the wellbore volume, and the pumping discharge rate is 6-10 m³ / h. 3 / min.

[0034] Compared with existing technologies, this complex fracture fracturing method for tight sandstone reservoirs combines liquid carbon dioxide with conventional hydraulic fracturing. Liquid carbon dioxide reaches a supercritical state under formation temperature and pressure. Utilizing the superior fluidity and diffusivity of supercritical carbon dioxide, it further increases the complexity of fractures beyond the creation of long and highly conductive fractures by conventional hydraulic fracturing. At the same time, the weakly acidic environment brought by carbon dioxide inhibits clay expansion and reduces reservoir damage, ultimately improving the stimulation effect of tight sandstone. Attached Figure Description

[0035] To more clearly illustrate the specific embodiments of the present invention or the technical solutions in the prior art, the drawings used in the description of the specific embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.

[0036] Figure 1 Flowchart for on-site carbon dioxide injection

[0037] Figure 2 This is a hydraulic fracturing construction curve diagram of complex fractures in tight sandstone reservoirs provided in an embodiment of the present invention. Detailed Implementation

[0038] To make the objectives, technical solutions, and advantages of this invention clearer, the invention will be further described in detail below with reference to embodiments. It should be understood that the specific embodiments described herein are only for explaining the invention and are not intended to limit the invention; that is, the described embodiments are merely a part of the embodiments of this invention, and not all of them.

[0039] Therefore, the following detailed description of the embodiments of the present invention 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 present invention without inventive effort are within the scope of protection of the present invention.

[0040] Unless otherwise specified, the experimental methods used in the following examples are conventional methods; unless otherwise specified, the reagents and materials used in the following examples are commercially available.

[0041] This invention provides a method for fracturing complex fractures in tight sandstone reservoirs, comprising the following steps:

[0042] (1) Pump high-viscosity bio-glue fracturing fluid into the target layer as a pre-fracturing fluid.

[0043] Furthermore, the pre-fluid is prepared by mixing 1.9–2.2% polymer thickener, 0.1–0.15% nano-repellent agent, 0.3–0.5% high-efficiency anti-swelling agent, and the balance water, with a base fluid viscosity of 90–110 mPa·s and a 170s... -1 The viscosity under high-speed shear is >80 mPa·s. The pre-filled liquid volume is 10%-20% of the total liquid volume for construction, and the pump discharge rate is 6-10 m³ / s. 3 / min.

[0044] In this step, the purpose of pumping pre-flush fluid is to form the main fracture near the wellbore with high-viscosity fluid, reduce fluid loss and improve fracture creation efficiency, and at the same time create conditions for creating complex fractures at the far end with supercritical carbon dioxide.

[0045] (2) Pump liquid carbon dioxide into the target layer.

[0046] Furthermore, the preferred amount of liquid carbon dioxide used is 50–100 mg / L. 3 The preferred injection displacement is 3-4m³. 3 / min.

[0047] In this step, the liquid carbon dioxide on the surface is stored under pressure at -20℃. The pumping equipment injects the liquid carbon dioxide into the bottom of the well through a circulating cold pump. Under the action of temperature and pressure at the bottom of the well, it reaches a supercritical state (temperature > 31.06℃, pressure > 7.38MPa). At this time, the carbon dioxide is in a special miscible state with a density of 0.6-0.9g / cm3 and a viscosity of 0.02mPa·s, which can achieve deep penetration and increase the complexity of the fracture.

[0048] (3) Inject bio-glue fracturing fluid systems of different viscosities sequentially into the target layer. This step is divided into three stages:

[0049] First stage: Pump low-viscosity bio-glue fracturing fluid mixed with 70 / 140 mesh ceramsite into the target layer; the viscosity of the low-viscosity bio-glue fracturing fluid is 8-15 mPa·s, the 70 / 140 mesh ceramsite is added in a slug-type manner, and the sand ratio is 3%-7%.

[0050] Second stage: Pumping medium-high viscosity bio-glue fracturing fluid mixed with 40 / 70 mesh ceramsite into the target layer; wherein, the viscosity of the medium-high viscosity bio-glue fracturing fluid is 60-80 mPa·s, the 40 / 70 mesh ceramsite is added continuously, and the sand ratio is 7%-18%.

[0051] The third stage: pumping high-viscosity bio-glue fracturing fluid mixed with 20 / 40 mesh ceramsite into the target layer; the viscosity of the high-viscosity bio-glue fracturing fluid is 90-110 mPa·s, the 20 / 40 mesh ceramsite is added continuously, and the sand ratio is 19-33%;

[0052] Furthermore, in the first stage mentioned above, the low-viscosity bio-adhesive fracturing fluid is prepared by mixing 0.3-0.5% polymer thickener, 0.1-0.15% nano-displacement agent, 0.3-0.5% high-efficiency anti-swelling agent and the balance water, with a base fluid viscosity of 8-15 mPa·s.

[0053] Furthermore, in the second stage described above, the medium-to-high viscosity bio-adhesive fracturing fluid is prepared by mixing 1.3–1.6% polymer thickener, 0.1–0.15% nano-displacement agent, 0.3–0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 60–80 mPa·s, and the 170s... -1 The viscosity under high-speed shear is >50 mPa·s.

[0054] Furthermore, in the third stage mentioned above, the high-viscosity bio-adhesive fracturing fluid is prepared by mixing 1.9–2.2% polymer thickener, 0.1–0.15% nano-repellent agent, 0.3–0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 90–110 mPa·s, and the viscosity under high-speed shear at 170 s⁻¹ is >80 mPa·s.

[0055] Furthermore, in the above three stages, the usage of 70 / 140 mesh ceramsite is 5%-10%, the usage of 40 / 70 mesh ceramsite is 10%-20%, and the usage of 20 / 40 mesh ceramsite is 70%-85%.

[0056] Furthermore, in the above three stages, the pumping discharge rate is 6-10 m³ / h. 3 / min.

[0057] In this step, the purpose of sequentially pumping different viscosities of bio-adhesive fracturing fluid systems includes: low-viscosity bio-adhesive carrying 70 / 140 mesh ceramsite to fill the micro-complex fracture system formed by supercritical carbon dioxide; medium- and high-viscosity bio-adhesive carrying 40 / 70 mesh ceramsite to polish the fracture wall and improve fracture creation efficiency, while simultaneously filling branch fractures below the main fracture; and high-viscosity bio-adhesive carrying 20 / 40 mesh ceramsite to fill the main fracture system and improve conductivity.

[0058] (4) Inject medium-viscosity bio-glue fracturing fluid with a viscosity of 30-50 mPa·s and water into the target layer in sequence for replacement construction.

[0059] Further, in this step, the medium-viscosity bio-adhesive fracturing fluid is prepared by mixing 0.8–1.2% polymer thickener, 0.1–0.15% nano-displacement agent, 0.3–0.5% high-efficiency anti-swelling agent, and the balance water, with a base fluid viscosity of 30–50 mPa·s and a 170s... -1 The viscosity under high-speed shear is >20 mPa·s.

[0060] Furthermore, the displacement volume of the medium-viscosity bio-adhesive is 0.6 times the wellbore volume, the displacement volume of the clean water is 0.5 times the wellbore volume, and the pumping discharge rate is 6-10 m³ / h. 3 / min.

[0061] In this step, the purpose of using medium-viscosity bio-glue fracturing fluid and clean water in sequence for displacement is that the medium-viscosity bio-glue can better displace the sand in the wellbore to the formation, while the excessive displacement with clean water can better clean the pumping equipment and pipelines, ensuring the smooth operation of subsequent operations.

[0062] The specific embodiments of the present invention will be further described below with reference to the accompanying drawings and examples.

[0063] Example 1

[0064] The method described in this application was used to perform fracturing on a single well in the Sulige area. The basic characteristics of the well are as follows: reservoir depth 3300m, permeability 0.5mD, porosity 12%, reservoir thickness 10m, well temperature 100℃, formation pressure 30MPa, maximum principal stress 60-65MPa, minimum principal stress 52-58MPa, clay mineral content 15-20%, the main component is imidazoline mixed layer, Young's modulus 22GPa, Poisson's ratio 0.23, well completion was performed using Ф139.7mm casing cementing, and fracturing was performed using casing injection.

[0065] The specific steps are as follows:

[0066] Step (1): Inject pre-flush fluid into the target formation and use high-viscosity fluid to create main fractures in the near-wellbore zone, reduce near-wellbore fluid loss, and increase fracture length.

[0067] When pumping the pre-fluid, quickly increase the discharge rate to 6.5m. 3 The flow rate of the injection fluid is 60 m³ / min, which helps reduce the formation of multiple fractures near the wellbore. The pre-injection fluid volume in this step is 60 m³ / min. 3 The pre-fluid formulation consists of 2.2% polymer thickener, 0.1% nano-repellent agent, 0.3% high-efficiency anti-swelling agent, and the balance being water. The base fluid viscosity is 98 mPa·s, and the 170s viscosity is... -1 The viscosity under high-speed shear is 85 mPa·s.

[0068] Step (2): Inject liquid carbon dioxide into the target layer at a rate of 80m³. 3 The preferred injection displacement is 3.5m³. 3 / min.

[0069] When pumping carbon dioxide, follow the instructions. Figure 1 The process shown involves first circulating and cooling the carbon dioxide injection equipment through a circulating pressure-maintaining pipeline, and then pumping the carbon dioxide from the storage tank to the target layer through a high-pressure pipeline.

[0070] In multi-stage pumping fracturing operations, after the first stage of carbon dioxide pumping is completed, the circulating pressure-maintaining pipeline continues to circulate, ensuring that the carbon dioxide remains in a flowing state within the pipeline. This eliminates the need for a cold pump before subsequent stages of pumping, enabling continuous construction.

[0071] Step (3): The total volume of bio-glue fracturing fluid of different viscosities pumped into the formation is 380m³. 3 It includes three stages:

[0072] Phase 1: Low-viscosity bio-adhesive fracturing fluid carrying 70 / 140 mesh ceramsite is pumped to the target formation using a plug pump. The low-viscosity bio-adhesive fluid volume is 120m³. 3 70 / 140 mesh ceramsite 3.4m 3 The sand ratio is 5-7%, and the construction discharge volume is 8m³. 3 / min, in this stage, the low-viscosity liquid carrying small-diameter ceramic particles helps to fill the complex fractures formed by supercritical carbon dioxide in the early stage, and also helps to reduce near-wellbore filtration loss and increase the length of the main fracture.

[0073] Phase Two: Medium-to-high viscosity bio-adhesive fracturing fluid carrying 40 / 70 mesh ceramic particles is continuously pumped to the target formation. The volume of medium-to-high viscosity bio-adhesive fluid is 100 m³. 3 40 / 70 mesh ceramsite 8m 3 The sand ratio of the mixed sand is 7-16%, and the construction discharge volume is 8m³. 3 / min, in this stage, the high viscosity liquid carrying small and medium-sized ceramic particles helps to increase the proppant transport distance and improve the proppant laying effect at the crack tip.

[0074] Phase 3: High-viscosity bio-adhesive fracturing fluid carrying 20 / 40 mesh ceramic aggregate is continuously pumped to the target layer. The volume of high-viscosity bio-adhesive fluid is 150 mg / L. 3 20 / 40 mesh ceramsite 38.5m 3 The sand ratio of the mixed sand is 19-32%, and the construction discharge volume is 8m³. 3 / min, the high viscosity liquid carrying large-diameter ceramic particles in this stage helps to improve the conductivity of the main fracture.

[0075] Step (4): Pump medium-viscosity bio-gel mixed with clean water into the wellbore sequentially for displacement construction. 20m of medium-viscosity bio-gel is used. 3 15m of clean water 3 Construction discharge volume 8m 3 / min.

[0076] In this implementation case, the low-viscosity bio-adhesive fracturing fluid is prepared by mixing 0.35% polymer thickener, 0.1% nano-displacement agent, 0.3% high-efficiency anti-swelling agent and the balance water, and its base fluid viscosity is 10 mPa·s.

[0077] The medium-viscosity bio-adhesive fracturing fluid is prepared by mixing 1.0% polymer thickener, 0.1% nano-displacement agent, 0.3% high-efficiency anti-swelling agent, and the balance water. Its base fluid viscosity is 42 mPa·s, and its 170 s⁻¹ viscosity is 170 s⁻¹. -1 The viscosity under high-speed shear is 25 mPa·s.

[0078] The medium-to-high viscosity bio-adhesive fracturing fluid is prepared by mixing 1.6% polymer thickener, 0.1% nano-displacement agent, 0.3% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 75 mPa·s, and the 170s viscosity is... -1 The viscosity under high-speed shear is 55 mPa·s.

[0079] The high-viscosity bio-adhesive fracturing fluid is prepared by mixing 2.2% polymer thickener, 0.1% nano-displacement agent, 0.3% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 98 mPa·s, and the 170s viscosity is... -1 The viscosity under high-speed shear is 85 mPa·s.

[0080] Using this method, after fracturing operations, the unobstructed flow rate of the production test gas was 322,817 cubic meters per day, which is more than 30% higher than that of the conventional fracturing test gas flow rate of adjacent wells on the same platform.

[0081] Figure 2 The pumping curve for the case well construction is shown, with 545m of fluid used in the construction. 3 80m of liquid carbon dioxide 3 Add 50m of sand 3 It is divided into 4 stages. Stage 1 is the pre-fluid pump injection stage, with a pumping displacement of 6.5m³. 3 / min, construction pressure 43-46MPa, liquid volume 60m³ 3 The base liquid viscosity was 98 mPa·s. The construction pressure dropped significantly in the later stage of pumping, indicating that the crack extension was good and the high viscosity liquid had a good crack-forming effect.

[0082] Phase 2 is the carbon dioxide injection phase, with an injection displacement of 3.5 m³. 3 / min, injection volume 80m 3 The construction pressure continued to decrease, dropping from 24.5 MPa to 23.5 MPa. This reflects that carbon dioxide reached a supercritical state under the influence of bottom hole temperature and pressure, exhibiting good fluidity and thus increasing the complexity of the fractures.

[0083] Phase 3 is the sand-mixing stage, which includes three parts: The first part uses a low-viscosity liquid to carry 70 / 140 mesh small-diameter ceramsite to fill complex cracks, with a construction flow rate of 8m³. 3 / min, liquid volume 120m 3 The base fluid viscosity is 10 mPa·s, and slug feeding is used with a sand addition rate of 3.4 m³. 3With a sand ratio of 5-7%, the construction pressure decreased from the initial 48.15 MPa to 35.5 MPa due to changes in wellbore friction.

[0084] The second part involves a medium-to-high viscosity liquid carrying 40 / 70 mesh small-diameter ceramic particles to increase the proppant transport distance and improve the proppant application effect at the crack tip. The construction flow rate is 8m³. 3 / min, liquid volume 100m 3 The base fluid viscosity is 75 mPa·s. A slug feed and low sand ratio are used for continuous sand addition, with a sand addition rate of 8 m³ / s. 3 With a sand ratio of 7-16%, the proppant slightly increased in pressure after entering the formation during this stage. After slug grinding, the pressure decreased from 37.8 MPa to 32.7 MPa, reflecting a good fracture propagation state and proppant placement effect.

[0085] The third part involves continuously adding sand using a high-viscosity liquid to carry 20 / 40 mesh large-particle ceramsite, improving the conductivity of the main fracture in the near-wellbore zone, with a construction discharge rate of 8m³. 3 / min, liquid volume 150m 3 The base liquid viscosity is 98 mPa·s, and the sand addition is 38.5 m³. 3 With a sand ratio of 19-32%, the construction pressure is relatively stable during this stage, which reflects the crack width well and allows for smooth sand addition.

[0086] Phase 4 is the replacement liquid stage, which uses medium-viscosity bio-adhesive and water for replacement application. 20ml of medium-viscosity bio-adhesive is used. 3 15m of clean water 3 Construction discharge volume 8m 3 / min. Due to changes in wellbore friction and fluid column pressure, the construction pressure increased from 33MPa to 43MPa.

[0087] Comparative Example

[0088] In this case, adjacent wells at the same level and on the same platform were constructed using conventional hydraulic fracturing techniques, with a fracturing displacement of 8m³ / h. 3 The fracturing fluid used is a medium-to-high viscosity bio-gel fracturing fluid with a base fluid viscosity of 55 mPa·s, and the proppant carrying fluid is a high viscosity bio-gel fracturing fluid with a base fluid viscosity of 100 mPa·s. The total fluid volume is 500 m³ / min. 3 Sand addition amount 55m 3 The particle size was 20 / 40 mesh ceramsite, the sand ratio was 5-33%, and the unobstructed gas flow rate after fracturing was 245,128 cubic meters / day. This case study adopted a combination of supercritical carbon dioxide and conventional hydraulic fracturing technology, which improved the unobstructed gas flow rate by 31.7% under similar construction scale.

[0089] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, and not to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some or all of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for fracturing complex fractures in tight sandstone reservoirs, characterized in that, include: (1) Pump the pre-filled fluid into the target layer; (2) Pump liquid carbon dioxide into the target layer; (3) Injecting bio-glue fracturing fluid systems of different viscosities sequentially into the target layer. This step is divided into three stages, including: First stage: Pump low-viscosity bio-glue fracturing fluid mixed with 70 / 140 mesh ceramsite into the target layer; wherein, the viscosity of the low-viscosity bio-glue fracturing fluid is 8-15 mPa·s, the 70 / 140 mesh ceramsite is added in a slug-type manner, and the sand ratio is 3%-7%. Second stage: Pumping medium-high viscosity bio-glue fracturing fluid mixed with 40 / 70 mesh ceramsite into the target layer; wherein, the viscosity of the medium-high viscosity bio-glue fracturing fluid is 60-80 mPa·s, the 40 / 70 mesh ceramsite is added continuously, and the sand ratio is 7%-18%. The third stage involves pumping high-viscosity bio-glue fracturing fluid mixed with 20 / 40 mesh ceramsite into the target layer. The viscosity of the high-viscosity bio-glue fracturing fluid is 90-110 mPa·s, and the 20 / 40 mesh ceramsite is added continuously with a sand ratio of 19-33%. (4) Inject medium-viscosity bio-glue fracturing fluid with a viscosity of 30-50 mPa·s and water into the target layer in sequence for replacement construction.

2. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (1), the pre-fluid is a high-viscosity bio-glue fracturing fluid, which is prepared by mixing 1.9-2.2% polymer thickener, 0.1-0.15% nano-displacement agent, 0.3-0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 90-110 mPa·s, and the 170s... -1 The viscosity under high-speed shear is >80 mPa·s.

3. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (1), the pre-fluid volume is 10%-20% of the total construction fluid volume, and the pump discharge rate is 6-10m³. 3 / min.

4. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (2), the injection volume of liquid carbon dioxide is 50-100 m³. 3 The injection displacement is 3-4m³. 3 / min.

5. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (3), the low-viscosity bio-adhesive fracturing fluid is prepared by mixing 0.3-0.5% polymer thickener, 0.1-0.15% nano-displacement agent, 0.3-0.5% high-efficiency anti-swelling agent and the balance water, with a base fluid viscosity of 8-15 mPa·s.

6. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (3), the medium-high viscosity bio-adhesive fracturing fluid is prepared by mixing 1.3-1.6% polymer thickener, 0.1-0.15% nano-displacement agent, 0.3-0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 60-80 mPa·s, and the 170s... -1 The viscosity under high-speed shear is >50 mPa·s.

7. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (3), the high-viscosity bio-adhesive fracturing fluid is prepared by mixing 1.9–2.2% polymer thickener, 0.1–0.15% nano-displacement agent, 0.3–0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 90–110 mPa·s, and the 170s... -1 The viscosity under high-speed shear is >80 mPa·s.

8. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (3), the amount of 70 / 140 mesh ceramsite used is 5%-10%, the amount of 40 / 70 mesh ceramsite used is 10%-20%, and the amount of 20 / 40 mesh ceramsite used is 70%-85%.

9. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (3), the pumping rate of fracturing fluid in the three stages is 6-10 m³ / h. 3 / min.

10. The method for fracturing complex fractures in tight sandstone reservoirs according to claim 1, characterized in that, In step (4), the medium-viscosity bio-adhesive fracturing fluid is prepared by mixing 0.8–1.2% polymer thickener, 0.1–0.15% nano-displacement agent, 0.3–0.5% high-efficiency anti-swelling agent, and the balance water. The base fluid viscosity is 30–50 mPa·s, and the 170s... -1 Viscosity >20 mPa·s under high-speed shear; In step (4), the displacement volume of the medium-viscosity bio-adhesive is 0.6 times the wellbore volume, the displacement volume of the clean water is 0.5 times the wellbore volume, and the pumping discharge rate is 6-10 m³ / h. 3 / min.

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