Reservoir fracturing method and application

Abstract

The application discloses a reservoir fracturing method and application. The method comprises the following steps: obtaining a wellhead construction pressure curve according to an actual fracturing construction and classifying construction pressure curve features. According to the curve classification, a different rubber plug temporary plugging process is adopted to inject a delayed cross-linking slick water and a small particle size proppant into a fracturing fracture to form a solid-liquid two-phase mixture rubber plug; then, low-viscosity slick water or low-viscosity slick water sand-carrying liquid is injected to displace the formed rubber plug to a micro-crack and a fracture tip region of the fracturing fracture, and the uniformity of the fracturing fracture and the fracture complexity are improved. The application can improve the fluid net pressure in the fracturing fracture, reduce liquid filtration loss, temporarily plug the fracture tip, improve the uniformity of the fracturing fracture and improve the complexity of the fracturing fracture, so that the fracturing reconstruction effect is improved and the oil / gas production is increased.

Description

Technical Field

[0001] This invention relates to the field of fracturing technology, specifically to reservoir fracturing methods and applications. Background Technology

[0002] For large-scale slickwater volumetric fracturing in unconventional oil and gas reservoirs, the uniformity and complexity of fracture propagation have a significant impact on the fracturing effect. Besides factors such as reservoir heterogeneity, mechanical characteristics, the degree and distribution of natural fractures, and differences in horizontal principal stresses, the fracturing process and construction parameters also have a crucial influence on the uniformity and complexity of fracture propagation.

[0003] To improve the uniformity and complexity of fracturing fractures in unconventional oil and gas reservoirs, based on reservoir geological-engineering parameter characteristics and natural fracture research, domestic and international researchers have conducted fine-tuning of parameters such as fracturing segmentation and clustering, fracturing fluid displacement, fracturing fluid properties, and proppant concentration to enhance fracture size and complexity. The fine-density perforation volume fracturing process can significantly increase the fracturing volume and complexity by increasing the number of perforation clusters per segment and reducing the spacing between perforation clusters. However, this process, with its large number of perforation clusters and small cluster spacing, limits the uniformity of fracture propagation and leads to significant differences in fracture propagation between different perforation clusters, resulting in reduced fracture complexity. To maximize the uniformity and complexity of fracturing fractures in unconventional oil and gas reservoirs, ball-dropping and temporary plugging techniques have been developed both domestically and internationally. Temporary plugging at the fracture mouth and within the fracture is a commonly used fracturing plugging technique. It involves pumping in solid plugging materials to temporarily seal the perforation orifice and fracture interior, thereby increasing the net pressure of the fluid at the fracture mouth and within the fracture. This promotes uniform propagation and directional change of fracturing fractures in different perforation clusters, and increases the complexity of the fracturing fractures. Existing fracturing plugging techniques mainly rely on plugging balls or plugging agents, resulting in significant variations in plugging effectiveness, with poor results in some reservoirs. Besides requiring specific fracturing pumping procedures, plugging with balls or plugging agents necessitates specialized design of plugging measures and pre-fracturing preparations, making the construction process relatively complex. Furthermore, it incurs additional costs for fracturing fluid, plugging balls, and plugging agents. The overall cost of plugging balls and plugging agents is high, leading to high overall costs when implementing temporary plugging techniques on a large scale. Summary of the Invention

[0004] The purpose of this invention is to overcome the problems of complex procedures and high overall costs of existing temporary plugging technology for unconventional oil and gas reservoir fracturing, and to provide a reservoir fracturing method and application. This method adopts a rubber plug temporary plugging process design to promote uniform propagation of fracturing fractures and increase fracture complexity, thereby improving the uniformity and complexity of fracturing fractures.

[0005] To achieve the above objectives, the first aspect of the present invention provides a reservoir fracturing method, the method comprising the following steps:

[0006] (1) Classify the wellhead construction pressure curves; among them, the wellhead construction pressure curves that show a stable or slightly fluctuating trend are Class I curves, the wellhead construction pressure curves that show a downward trend and then show a basically stable or continuously downward trend after a certain decline are Class II curves, and the wellhead construction pressure curves that show an upward trend and the difference between the construction pressure limit and the wellhead construction pressure is above 10MPa are Class III curves.

[0007] (2) Different rubber plugging processes are used for the above different types of curves to inject delayed cross-linked slickwater and small-particle-size proppant into the fracturing fracture to form a solid-liquid two-phase mixture rubber plug; wherein, for type I curves, a first rubber plugging process is used; the first rubber plugging process uses a 2-stage rubber plugging process; for type II curves, a second rubber plugging process is used; the second rubber plugging process uses a 1-3 stage rubber plugging process; for type III curves, a third rubber plugging process is used; the third rubber plugging process uses a 1-stage rubber plugging process.

[0008] (3) Subsequent injection of low-viscosity slickwater or low-viscosity slickwater carrying sand fluid to replace the formed rubber plugs in the micro-cracks and crack tip regions of the fracturing fracture, thereby improving the uniformity and complexity of the fracturing fracture; wherein, the viscosity of the delayed crosslinking slickwater after complete crosslinking is 70-100 mPa.s, and the viscosity of the low-viscosity slickwater or low-viscosity slickwater carrying sand fluid is 3-5 mPa.s.

[0009] A second aspect of the present invention provides the application of the aforementioned method in shale oil / gas reservoirs, tight sandstone gas reservoirs, or coalbed methane reservoirs.

[0010] The beneficial technical effects achieved by the present invention through the above technical solution are as follows:

[0011] This invention relates to a process for improving fluid pressure, fracture homogeneity, and complexity within fracturing fractures. By implementing this process and method, the fluid pressure and net pressure within the fracturing fractures can be increased in a timely manner, thereby enhancing the fracturing effect. This invention's process and method are applicable not only to matrix-type and fractured shale and tight sandstone reservoirs but also to coalbed methane reservoirs. Similarly, this invention's process and method are applicable to unconventional oil and gas reservoirs at different depths, including shallow and deep unconventional oil and gas reservoirs.

[0012] (1) The present invention performs a temporary plugging process to increase net pressure in a timely manner according to reservoir characteristics, wellhead construction pressure curve and process requirements. No construction preparation is required in advance. It can be implemented multiple times to increase the net pressure in the fracture as much as possible. At the same time, in the process of increasing net pressure, it can promote the uniform expansion of multiple clusters of fractures and increase the complexity of the fracturing fractures, thereby improving the fracturing effect.

[0013] (2) This invention utilizes a temporary plugging process combining delayed cross-linked slickwater and high-concentration small-particle-size proppant to increase the net pressure inside the fracture. The overall process is simple and easy to operate. On-site, only a sand mixing truck is needed to prepare the delayed cross-linked slickwater fracturing fluid online, and then add high-concentration small-particle-size proppant to inject into the reservoir fracture to increase the net pressure inside the fracture.

[0014] (3) The method of temporarily plugging the fracture with rubber plugs used in this invention to increase the net pressure in the fracture can be applied to various reservoir types such as shale, tight sandstone and coalbed methane, and to increase the effect of fracturing. Attached Figure Description

[0015] Figure 1 This is a schematic diagram of a fracture formed by a fracturing method proposed in this invention;

[0016] Figures 2a-2c These are diagrams of the three types of wellhead construction pressure curves proposed in this invention;

[0017] Figure 3 This is a schematic flowchart of a reservoir fracturing method proposed in this invention;

[0018] Figure 4a This is a construction curve diagram of temporary plugging fracturing construction on a proportional basis;

[0019] Figure 4b This is a construction curve diagram of the fracturing section in the embodiment.

[0020] Explanation of reference numerals in the attached figures

[0021] 1—Unconventional oil and gas reservoir; 2—Secondary fracture tip temporarily plugged by proppant;

[0022] 3—Propionate temporarily plugs the tip of the main fracture; 4—Rubber plug temporarily plugs the fracturing fracture area;

[0023] 5—Delayed crosslinking slickwater; 6—Small particle size proppant;

[0024] 7—Secondary fractures of the hydraulic fracturing fracture; 8—Proppant temporarily plugged with rubber plugs for subsequent injection;

[0025] 9—The low-viscosity slickwater is temporarily plugged with a rubber stopper after injection;

[0026] 10—The cracked area replaced by the rubber stopper after temporary plugging;

[0027] 11—Complex secondary cracks formed after temporary plugging with rubber stoppers. Detailed Implementation

[0028] The endpoints and any values ​​of the ranges disclosed herein are not limited to the precise ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoint values ​​of the various ranges, the endpoint values ​​of the various ranges and individual point values, and individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed herein.

[0029] The first aspect of this invention provides a reservoir fracturing method, the method comprising the following steps:

[0030] (1) Classify the wellhead construction pressure curves; among them, the wellhead construction pressure curves that show a stable or slightly fluctuating trend are Class I curves, the wellhead construction pressure curves that show a downward trend and then show a basically stable or continuously downward trend after a certain decline are Class II curves, and the wellhead construction pressure curves that show an upward trend and the difference between the construction pressure limit and the wellhead construction pressure is above 10MPa are Class III curves.

[0031] (2) Different rubber plugging processes are used for the above different types of curves to inject delayed cross-linked slickwater and small-particle-size proppant into the fracturing fracture to form a solid-liquid two-phase mixture rubber plug; wherein, for type I curves, a first rubber plugging process is used; the first rubber plugging process uses a 2-stage rubber plugging process; for type II curves, a second rubber plugging process is used; the second rubber plugging process uses a 1-3 stage rubber plugging process; for type III curves, a third rubber plugging process is used; the third rubber plugging process uses a 1-stage rubber plugging process.

[0032] (3) Subsequent injection of low-viscosity slickwater or low-viscosity slickwater carrying sand fluid to replace the formed rubber plugs in the micro-cracks and crack tip regions of the fracturing fracture, thereby improving the uniformity and complexity of the fracturing fracture; wherein, the viscosity of the delayed crosslinking slickwater after complete crosslinking is 70-100 mPa.s, and the viscosity of the low-viscosity slickwater or low-viscosity slickwater carrying sand fluid is 3-5 mPa.s.

[0033] The method of this invention classifies different construction processes based on the obtained wellhead construction pressure curve variation characteristics. According to the classification, different rubber plug temporary plugging processes are used to inject delayed cross-linked slickwater and small-particle-size proppant into the fracturing fracture to form a solid-liquid two-phase mixture rubber plug. Then, low-viscosity slickwater or low-viscosity slickwater carrying sand fluid is injected to replace the formed rubber plug in the micro-fractures and fracture tip regions of the fracturing fracture, thereby improving the uniformity and complexity of the fracturing fracture.

[0034] In this invention, a Type I curve refers to a wellhead construction pressure curve that exhibits a stable or slightly fluctuating trend. This mainly refers to a continuous wellhead construction pressure value with small-amplitude high-frequency sawtooth fluctuations or small-amplitude low-frequency fluctuations under stable construction flow conditions, where a first rubber plug temporary plugging process is employed. Specifically, the first rubber plug temporary plugging process uses a two-stage rubber plugging method. The first stage of rubber plugging occurs at 30-40% of the total designed fracturing fluid volume, and the second stage occurs at 60-70% of the total fracturing fluid volume. A generally stable or slightly fluctuating wellhead construction pressure includes a small, slow rise followed by a slow fall, a small, slow fall followed by a slow rise, and a small, rapid sawtooth fluctuation. The pressure fluctuation range in the wellhead construction pressure curve is within 2.5% of the average pressure of each stage of construction, and the wellhead construction pressure difference is within 3-5 MPa.

[0035] When the wellhead construction pressure curve rapidly decreases to a certain extent and then stabilizes or shows a continuous downward trend, it is classified as a Type II curve. "Rapidly decreasing to a certain extent and then stabilizing" mainly refers to the wellhead construction pressure stabilizing after a rapid decrease to a certain value under stable construction flow conditions. "Continuous decrease in wellhead construction pressure" refers to a continuous, small decrease in wellhead construction pressure under fixed construction flow conditions, requiring temporary plugging with a second rubber plug. Based on the relationship between the fluid volume and the total fluid volume after the wellhead construction pressure stabilizes or during the small decrease phase, the second rubber plugging process uses 1-3 stages of rubber plugs. Wellhead construction pressure decrease includes a rapid decrease followed by a stable or continuous slow decrease, where the rapid decrease exceeds 10%, the rate of decrease exceeds 7.5 MPa / min, and the decrease value is greater than 10 MPa; or, a continuous slow decrease occurs at a rate of 1-5 MPa / min, with an overall decrease value greater than 5 MPa.

[0036] When the wellhead construction pressure curve shows a slow upward trend and the difference between the construction pressure limit and the wellhead construction pressure is greater than 10 MPa, it is classified as a Type III curve. This mainly refers to a situation where the wellhead construction pressure value continuously and slowly increases when the construction flow rate is stable, and the difference between the maximum wellhead construction pressure value and the construction pressure limit of the fracturing equipment exceeds 10 MPa. In this case, a third rubber plug temporary plugging process is adopted. The third rubber plug temporary plugging process uses a first-stage rubber plug, and the timing of the first-stage rubber plug temporary plugging is 50-60% of the total fracturing fluid volume. The slow increase in wellhead construction pressure refers to a continuous increase in the wellhead construction pressure value, with the increase rate being less than 1 MPa / min. The construction pressure limit refers to the fracturing construction pressure limit of the on-site construction equipment, which is mainly determined by the ultimate bearing capacity of the fracturing construction equipment, the fracturing wellhead, and the fracturing casing.

[0037] According to some embodiments of the present invention, in Type I curves, the pressure fluctuation range of the wellhead construction pressure curve is within 2.5% of the average pressure of the stage construction, and the pressure difference at the wellhead is within 3-5 MPa.

[0038] According to some embodiments of the present invention, in the Type II curve, the wellhead construction pressure curve shows a rapid decrease to a certain extent followed by a basic stabilization or a continuous downward trend. The decrease in the wellhead construction pressure value in the wellhead construction pressure curve exceeds 10%, the rate of decrease in the wellhead construction pressure exceeds 7.5 MPa / min, and the decrease in the wellhead construction pressure value is greater than 10 MPa; or, the rate of decrease in the wellhead construction pressure is 1-5 MPa / min, and the overall decrease in the wellhead construction pressure value is greater than 5 MPa.

[0039] According to some embodiments of the present invention, in the Type III curve, the rise in wellhead construction pressure is less than 1 MPa / min, and the difference between the construction pressure limit and the wellhead construction pressure is more than 10 MPa, preferably 10-15 MPa.

[0040] According to some embodiments of the present invention, the small-particle-size proppant is at least one of 100 / 200 mesh proppant, 70 / 140 mesh proppant, and 40 / 70 mesh proppant.

[0041] According to some embodiments of the present invention, the small-particle-size proppant is ceramsite and / or quartz sand.

[0042] According to some embodiments of the present invention, the wellhead construction pressure increase threshold after using the rubber plug temporary plugging process is as follows:

[0043] First threshold range: Wellhead construction pressure increase > 5 MPa;

[0044] Second threshold range: 3MPa ≤ wellhead construction pressure increase value ≤ 5MPa;

[0045] The third threshold range: wellhead construction pressure increase value < 3MPa.

[0046] According to the fracturing process described above, the wellhead construction pressure increase thresholds after adopting the rubber plug temporary plugging process are as follows: First threshold range: wellhead construction pressure increase > 5 MPa; Second threshold range: 3 MPa ≤ wellhead construction pressure increase ≤ 5 MPa; Third threshold range: wellhead construction pressure increase < 3 MPa. The delayed crosslinking slickwater volume, proppant type, and proppant-sand ratio for the second and third stages of each type of temporary plugging process are optimized based on these threshold ranges.

[0047] In this invention, when the construction discharge is stable, if the wellhead construction pressure is generally stable or fluctuates slightly, a first rubber plug temporary plugging process is adopted, and the first rubber plug temporary plugging process adopts a two-stage rubber plug temporary plugging.

[0048] According to some embodiments of the present invention, in the first rubber plug temporary plugging process, the timing of the first-stage rubber plug temporary plugging is 30-40% of the total fluid volume of the fracturing design, and the timing of the second-stage rubber plug temporary plugging is 60-70% of the total fluid volume of the fracturing operation.

[0049] According to some embodiments of the present invention, in the first rubber stopper temporary plugging process, the volume of the delayed crosslinking slickwater used for the first-stage rubber stopper temporary plugging is 40-50 m³. 3 ;

[0050] If the wellhead working pressure increases to the first threshold after the first-stage rubber plug temporary plugging, the volume of delayed cross-linking slickwater from the second-stage rubber plug temporary plugging will be 30-40 m³. 3 ;

[0051] If the wellhead working pressure increases to the second threshold after the first-stage rubber plug temporary plugging, the volume of delayed cross-linking slickwater in the second-stage rubber plug temporary plugging process is 40-50m³. 3 ;

[0052] If the wellhead working pressure increases to the third threshold after the first-stage rubber plug temporary plugging, the volume of delayed cross-linking slickwater from the second-stage rubber plug temporary plugging is 50-60m³. 3 .

[0053] In this invention, the proppant-sand ratio of the second-stage rubber plug temporary plugging is optimized based on the change in wellhead construction pressure after the implementation of the first-stage rubber plug temporary plugging process.

[0054] According to some embodiments of the present invention, in the first rubber stopper temporary plugging process, the first-stage rubber stopper temporary plugging uses 100 / 200 mesh proppant, the proppant-to-sand ratio is 20-25%, and sand is added in one continuous sand ratio. According to other embodiments of the present invention, the first-stage rubber stopper temporary plugging uses 70 / 140 mesh proppant, the proppant-to-sand ratio is 15-20%.

[0055] According to some embodiments of the present invention, if the wellhead construction pressure increases to a first threshold after the implementation of the first-stage rubber plug temporary plugging, the second-stage rubber plug temporary plugging uses 100 / 200 mesh proppant, and the proppant sand ratio is reduced to 15-18%; or, the second-stage rubber plug temporary plugging uses 70 / 140 mesh proppant, and the proppant sand ratio is reduced to 13-15%.

[0056] According to some embodiments of the present invention, if the wellhead construction pressure increases to a second threshold after the implementation of the first-stage rubber plug temporary plugging, the proppant and sand ratio used in the second-stage rubber plug temporary plugging are the same as those used in the first-stage rubber plug temporary plugging.

[0057] According to some embodiments of the present invention, if the wellhead construction pressure increases to the third threshold after the implementation of the first-stage rubber plug temporary plugging, the second-stage rubber plug temporary plugging uses 40 / 70 mesh proppant with a sand ratio of 20-25%.

[0058] According to the present invention, if the wellhead construction pressure is stable or fluctuates very little before the implementation of the rubber plug temporary plugging process, it indicates that the natural fractures in the fracturing section of the reservoir are relatively underdeveloped and the fracturing fractures are relatively easy to propagate, and the fluid pressure, fluid loss, and fracture propagation in the fracturing fractures are basically balanced. For this type of fracturing section, a two-stage rubber plug temporary plugging process is designed to temporarily plug the fracture tip and increase the fluid pressure in the fracturing fracture.

[0059] According to the present invention, after the first-stage rubber plug temporary plugging process is implemented, low-viscosity slickwater and proppant are injected to form a sand-carrying fluid. The changes in wellhead construction pressure are observed in a timely manner, and the design of the second-stage rubber plug temporary plugging process parameters is further optimized based on the fluctuation range of the wellhead construction pressure.

[0060] According to some embodiments of the present invention, in the first rubber plug temporary plugging process, after the first-stage rubber plug temporary plugging is implemented, different second-stage rubber plug temporary plugging processes are adopted according to the increase in wellhead construction pressure.

[0061] In this invention, when the construction flow rate is stable, if the wellhead construction pressure drops rapidly to a certain level and then stabilizes, or if the construction pressure continues to drop slowly, a second rubber plug temporary plugging process is adopted; wherein, based on the relationship between the construction fluid volume and the total fluid volume after the wellhead construction pressure stabilizes or during the continuous drop phase, the second rubber plug temporary plugging adopts a 1-3 grade rubber plug temporary plugging process.

[0062] According to some embodiments of the present invention, in the second rubber plug temporary plugging process, if the amount of construction fluid during the wellhead construction pressure basically stable stage or the stage of slight decrease is less than 30% of the total design volume of fracturing fluid, the second rubber plug temporary plugging adopts a two-stage rubber plug temporary plugging. The timing of the first-stage rubber plug temporary plugging is 30-40% of the total fracturing construction fluid volume; the timing of the second-stage rubber plug temporary plugging is 60-70% of the total fracturing construction fluid volume.

[0063] According to some embodiments of the present invention, the volume of the delayed crosslinking slickwater temporarily plugged by the first-stage rubber stopper is 50-70 m³. 3 The process involves two stages of rubber stopper injection. The first stage involves a liquid volume of 20-30 ml. 3 The liquid volume in the second stage is 30-40m³. 3 .

[0064] According to some embodiments of the present invention, if the wellhead construction pressure increase after the first-stage rubber plugging reaches a first threshold, the delayed cross-linking slickwater volume of the second-stage rubber plugging process is 30-40 m³. 3 .

[0065] According to some embodiments of the present invention, if the wellhead construction pressure increases to a second threshold after the implementation of the first-stage rubber plug temporary plugging, the volume of the delayed cross-linked slickwater is referenced to the first-stage rubber plug temporary plugging.

[0066] According to some embodiments of the present invention, if the wellhead construction pressure rises to a third threshold after the first-stage rubber plugging, the volume of delayed cross-linked slickwater in the second-stage temporary plugging fracturing process is 40-50 m³. 3 .

[0067] According to some embodiments of the present invention, in the second rubber stopper temporary plugging process, the first stage of the first-stage rubber stopper temporary plugging uses 100 / 200 mesh proppant with a proppant-to-sand ratio of 15-20%; the second stage uses 70 / 140 mesh proppant with a proppant-to-sand ratio of 20-25%; or, the first stage of the first-stage rubber stopper temporary plugging uses 100 / 200 mesh proppant with a proppant-to-sand ratio of 20-25%; the second stage uses 100 / 200 mesh proppant with a proppant-to-sand ratio of 25-30%; or, the first stage uses 70 / 140 mesh proppant with a proppant-to-sand ratio of 15-20%; the second stage uses 70 / 140 mesh proppant with a proppant-to-sand ratio of 20-25%.

[0068] According to some embodiments of the present invention, the second-stage rubber plugging uses 40 / 70 mesh proppant. If the wellhead construction pressure after the first-stage rubber plugging reaches a first threshold, the proppant-to-sand ratio is 15-20%; if the wellhead construction pressure after the first-stage rubber plugging reaches a second threshold, the proppant-to-sand ratio is 18-22%; if the wellhead construction pressure after the first-stage rubber plugging reaches a third threshold, the proppant-to-sand ratio is 20-25%.

[0069] According to some embodiments of the present invention, in the second rubber plug temporary plugging process, if the fluid volume during the stage of basically stable or slightly decreased wellhead construction pressure reaches 40-60% of the designed total fluid volume, the second rubber plug temporary plugging process adopts a first-stage rubber plug temporary plugging, and the temporary plugging time is 65-70% of the total fluid volume of fracturing construction.

[0070] According to some embodiments of the present invention, the volume of the delayed crosslinking slickwater temporarily plugged by the first-stage rubber stopper is 50-70 m³. 3 The process involves two stages of injection to form the rubber stopper. In the first stage, the liquid volume is 20-30 ml. 3 The liquid volume in the second stage is 30-40m³. 3 .

[0071] According to some embodiments of the present invention, the first stage uses 70 / 140 mesh proppant with a proppant-to-sand ratio of 20-25%; the second stage uses 40 / 70 mesh proppant with a proppant-to-sand ratio of 20-25%.

[0072] According to some embodiments of the present invention, in the second rubber plug temporary plugging process, if the wellhead construction pressure drops rapidly and the drop exceeds 15% and the construction fluid volume is less than 30% of the total fracturing design fluid volume, the development of natural fractures in the fracturing section is determined by combining reservoir characteristics and wellhead construction pressure curve. The second rubber plug temporary plugging process adopts three-stage rubber plug temporary plugging. The timing of the first-stage rubber plug temporary plugging is 30-35% of the total fracturing fluid volume, the timing of the second-stage rubber plug temporary plugging is 50-60% of the total fluid volume, and the timing of the third-stage rubber plug temporary plugging is 70-75% of the total fluid volume.

[0073] According to some embodiments of the present invention, the volume of the delayed crosslinking slickwater temporarily plugged by the first-stage rubber stopper is 50-70 m³. 3 The process is implemented in two stages; the volume of the delayed cross-linking slickwater temporarily plugged in the second stage is 40-50 m³. 3 The volume of delayed cross-linking slickwater temporarily plugged by the third-stage rubber stopper is 30-40 m³. 3 .

[0074] According to some embodiments of the present invention, the first-stage rubber plug temporary plugging uses 100 / 200 mesh proppant, the proppant sand ratio in the first stage is 20-25%, and the proppant sand ratio in the second stage is 25-30%; or, the first-stage rubber plug temporary plugging uses 70 / 140 mesh proppant, the proppant sand ratio in the first stage is 15-20%, and the proppant sand ratio in the second stage is 20-25%.

[0075] According to some embodiments of the present invention, the second-stage rubber plugging uses 100 / 200 mesh or 70 / 140 mesh proppant. If the wellhead construction pressure after the implementation of the first-stage rubber plugging reaches a first threshold, the proppant-to-sand ratio is 15-20%; if the wellhead construction pressure after the implementation of the first-stage rubber plugging reaches a second threshold, the proppant-to-sand ratio is 18-20%; if the wellhead construction pressure after the implementation of the first-stage rubber plugging reaches a third threshold, the proppant-to-sand ratio is 20-25%.

[0076] According to some embodiments of the present invention, the third-stage rubber plug temporary plugging uses 40 / 70 mesh proppant. If the wellhead construction pressure increases to the first threshold after the second-stage rubber plug temporary plugging, the proppant-to-sand ratio is 15-20%; if the wellhead construction pressure increases to the second threshold after the second-stage rubber plug temporary plugging, the proppant-to-sand ratio is 18-22%; if the wellhead construction pressure increases to the third threshold after the second-stage rubber plug temporary plugging, the proppant-to-sand ratio is 20-25%.

[0077] In this invention, when the construction discharge rate is stable, if the wellhead construction pressure rises slowly and the difference between the construction pressure limit and the wellhead construction pressure is greater than 10 MPa, a third rubber plug temporary plugging process is adopted; wherein, the third rubber plug temporary plugging process adopts a first-level rubber plug temporary plugging.

[0078] According to some embodiments of the present invention, in the third rubber plug temporary plugging process, the timing of the first-stage rubber plug temporary plugging is 50-60% of the total fluid volume during fracturing.

[0079] According to some embodiments of the present invention, the volume of delayed crosslinking slickwater temporarily plugged with a first-stage rubber stopper is 40-50 m³. 3 .

[0080] According to some embodiments of the present invention, the first-stage rubber plug is temporarily plugged with 100 / 200 mesh proppant, and the proppant sand ratio is 20-25%; or, 70 / 140 mesh proppant is used, and the proppant sand ratio is 15-20%.

[0081] According to the present invention, the principle of temporary plugging with a rubber stopper is as follows: [Combined with...] Figure 1 The diagram illustrates a temporary plugging mode formed by a fracturing method. Ground fracturing equipment injects fracturing fluid and proppant into an unconventional oil and gas reservoir 1 to form a fracturing fracture. Delayed crosslinking slickwater 5 and small-particle proppant 6 are then injected to form a rubber plug for temporary plugging. Next, low-viscosity slickwater 9 or a proppant-carrying fluid containing proppant 8 is injected, displacing the previously injected delayed crosslinking slickwater 5 and small-particle proppant 6 to the tips of secondary fractures 2 and primary fractures 3. This forms a rubber plug temporary plugging area at the tips of the primary fracture 3 and secondary fractures 2, reducing the propagation of the original fracturing fractures in these areas. Subsequent injection of fracturing fluid forms a replaced fracture area 10 after the rubber plug temporary plugging. The increased fluid pressure in this replaced area forms secondary fractures 7 and complex secondary fractures 11 after the rubber plug temporary plugging, thereby increasing the complexity of the fracturing fractures. Meanwhile, for the propagation of fractures in horizontal well clusters, the temporary plugging of fracture tips between different perforation clusters can increase the net pressure in the fractures of different perforation clusters, thereby promoting the uniform propagation of fractures in different perforation clusters and increasing the uniformity of fracture propagation between different perforation clusters.

[0082] According to this invention, different curve types are classified based on the variation characteristics of the wellhead fracturing operation curves in unconventional oil and gas reservoirs. Different rubber plug temporary plugging processes are then employed according to these classifications:

[0083] (1) When the construction discharge rate 13a is stable, if the wellhead construction pressure 12a is generally stable or fluctuates slightly, such as Figure 2a As shown, the reservoir's overall natural fractures are underdeveloped and the hydraulic fractures propagate normally. The multi-stage rubber plugging process can help increase the fluid pressure in the hydraulic fractures and promote the complexity and uniformity of the hydraulic fracture propagation.

[0084] (2) When the construction discharge rate 13b is stable, if the wellhead construction pressure 12b drops rapidly to a certain level and then stabilizes or continues to drop slowly, such as Figure 2bAs shown, the fracturing reservoir section has well-developed natural fractures, and the fracturing fractures have connected to the natural fracture body. The fluid loss in the fracturing fractures is large, and it is necessary to use a temporary plugging process to increase the fluid pressure in the fracturing fractures and increase the complexity and uniformity of the fracturing fractures.

[0085] According to this invention, if the wellhead construction pressure drops rapidly to a certain level before multi-stage rubber plugging and then stabilizes or continues to drop slowly, it indicates that the fracturing fracture connects to the natural fracture zone / body, the fracturing fluid loss is relatively large, and the reduction in fracture fluid pressure will make it difficult for the fracturing fracture to expand over a large area. Simultaneously, it may cause some perforation clusters to arrest, leading to a decrease in the uniformity of the fracturing fracture. Therefore, it is necessary to use a mixture of slickwater and proppant to temporarily plug part of the fracture tip to increase the fluid pressure in the fracturing fracture. For sections with well-developed natural fractures, rubber plugging is implemented during periods when the wellhead construction pressure is relatively stable or continues to drop slightly. Depending on the construction situation, 1-3 stages of rubber plugging are used. For the first stage, 100 / 200 mesh proppant and / or 70 / 140 mesh proppant should be used simultaneously whenever possible. Subsequent stages can use 40 / 70 mesh proppant.

[0086] (3) When the construction discharge rate 13c is stable, if the wellhead construction pressure 12c rises slowly and the difference between the construction pressure limit and the wellhead construction pressure is greater than 10 MPa, such as Figure 2c As shown, the slow increase in wellhead drilling pressure indicates that the reservoir's natural fractures are underdeveloped and the fracturing fractures propagate slowly. If the difference between the drilling pressure limit and the wellhead drilling pressure is greater than 10 MPa, a process of increasing the net pressure within the fracture in one step can be selected. If the difference between the drilling pressure limit and the wellhead drilling pressure is less than 10 MPa, the rubber plug temporary plugging process of this invention is prone to temporary sand blockage. Therefore, this invention only considers the case where the difference between the drilling pressure limit and the wellhead drilling pressure is greater than 10 MPa.

[0087] According to this invention, if the wellhead construction pressure shows an upward trend before the implementation of the multi-stage rubber plug temporary plugging process, the decision on whether to implement the multi-stage rubber plug temporary plugging process is based on the difference between the fracturing construction pressure limit and the wellhead construction pressure, as well as the characteristics of the wellhead construction pressure increase, to increase the net pressure within the fracture. If the wellhead construction pressure rises slowly, it indicates that the reservoir's natural fractures are underdeveloped and the fracturing fractures are expanding slowly. If the difference between the construction pressure limit and the wellhead construction pressure is greater than 10 MPa, a single rubber plug temporary plugging is used to increase the net pressure within the fracture.

[0088] According to this invention, the temporary plugging process using delayed cross-linked slickwater typically involves a single-stage liquid volume exceeding one fracturing wellbore volume, which can be adjusted as needed during construction. Single-stage temporary plugging divides the liquid into 1-2 stages for plugging with rubber plugs, maximizing the plugging effect. After the first-stage plugging process, low-viscosity slickwater and proppant are injected to form a proppant-carrying fluid, and the changes in wellhead pressure are observed. Based on the effect of the first-stage plugging process, the parameters of the second-stage plugging process are further optimized. If a multi-stage plugging process is used to increase the fluid pressure within the fracture, the volume of the subsequent delayed cross-linked slickwater fracturing fluid can be adjusted based on the pressure changes after the preceding processes. If the wellhead pressure increase is not significant after the initial process, and the increase is less than 3 MPa, the volume can be increased by 10-20 m³ / s in subsequent processes. 3 Delayed crosslinking of slickwater; if the wellhead construction pressure is increased to more than 5 MPa, the subsequent improvement process can reduce the pressure by 10-20 m. 3 Delayed cross-linking slickwater.

[0089] According to this invention, to address the problem of temporarily plugging and increasing fluid pressure within unconventional oil and gas reservoirs during fracturing, a combination of delayed cross-linked slickwater fracturing fluid and small-particle proppant is injected into the fracturing fracture to form a solid-liquid two-phase mixture plug. After entering the fracturing fracture, the plug temporarily plugs the fracture tip and large-scale microfractures, increasing the fluid pressure within the fracture and thereby improving the uniformity and complexity of fracture propagation. The liquid used in the fracturing plugging process is delayed cross-linked slickwater. The drag-reducing agent in the slickwater fracturing fluid reacts with the cross-linking agent to form ultra-high viscosity slickwater. The cross-linking time can be controlled according to reservoir temperature and design requirements. The delayed cross-linked slickwater carries a high-sand-ratio, small-particle proppant (ceramsite or quartz sand) to form a plug consisting of an ultra-high viscosity liquid and solid proppant particles. After entering the fracturing fracture, the delayed cross-linked slickwater undergoes complete cross-linking to form an ultra-high viscosity liquid, reducing liquid loss. Because fracturing fluid carrying high-sand-ratio proppant has high viscosity, high-concentration, small-particle-size proppant can migrate to the fracture tip and reduce the propagation rate of the existing fracture, achieving temporary plugging of the fracture tip and micro-fractures. Delayed cross-linking slickwater mixed with high-concentration, small-particle-size proppant forms a rubber plug, which temporarily plugs the fracture tip or micro-fractures, increasing the fluid pressure within the fracture. Subsequent injection of low-viscosity slickwater or low-viscosity slickwater carrying proppant can further promote the formation of complex fractures, increasing their complexity. This invention's multi-stage rubber plugging process reduces fluid loss and temporarily plugs the fracture tip and micro-fractures after the rubber plug enters the fracturing fracture, thus reducing the propagation rate of the existing fracture and increasing the fluid pressure within the fracture. This promotes uniform fracture propagation and increases fracture complexity, thereby achieving the goal of increasing fracture complexity and improving fracturing stimulation effects.

[0090] According to the present invention, the proppant-to-sand ratio is optimized based on the characteristics of natural fracture development in the reservoir and the width of the hydraulic fracture.

[0091] According to some embodiments of the present invention, the small-particle-size proppant is a 100 / 200 mesh proppant and / or a 70 / 140 mesh proppant and / or a 40 / 70 mesh proppant. The small-particle-size proppant is ceramsite and / or quartz sand.

[0092] The proppant used in this invention is 100 / 200 mesh or 70 / 140 mesh small-particle-size quartz sand or ceramsite. The proppant type and particle size are selected based on the minimum particle size of the proppant in the fracturing design to increase net pressure within the fracture. Regarding the proppant concentration, if 100 / 200 mesh ceramsite or quartz sand is used, the proppant concentration is 15-30%; if 70 / 140 mesh ceramsite or quartz sand is used, the recommended concentration is 15-30%; and if 40 / 70 mesh ceramsite or quartz sand is used, the recommended concentration is 15-25%. If a multi-stage process for increasing net pressure within the fracture is adopted, the subsequent processes for increasing net pressure adjust the proppant concentration based on the pressure fluctuations after proppant addition in the previous processes to further improve the implementation effect. If the wellhead construction pressure increased significantly in the early stage of a single-stage process, the proppant concentration can be further increased by 5-10% during the subsequent implementation of the pressure-increasing process; if the wellhead construction pressure was increased too much in the early stage, the proppant concentration can be reduced by 5-10% during the subsequent implementation.

[0093] According to some embodiments of the present invention, the delayed crosslinking slickwater includes additives and auxiliary additives, wherein the additives include drag reducers, delayed crosslinking controlled crosslinking agents, and depolymerizers; and the auxiliary additives include clay stabilizers and drainage aids.

[0094] In this invention, the crosslinking agent for delayed crosslinking control controls the crosslinking time of the delayed crosslinked slickwater. The formulation needs to be optimized according to the reservoir temperature, reservoir depth and possible injection rate to ensure that the crosslinked slickwater begins to crosslink completely after entering the reservoir.

[0095] According to some embodiments of the present invention, the low-viscosity slippery water additive is a drag reducer, and the auxiliary additives include clay stabilizers and drainage aids.

[0096] According to some embodiments of the present invention, the low-viscosity slippery water carrying sand fluid comprises a mixed two-phase fluid of low-viscosity slippery water and proppant.

[0097] According to a particularly preferred embodiment of the present invention, a process for multi-stage rubber plugging in unconventional oil and gas reservoir fracturing is provided, combined with... Figure 1-3 The specific implementation plan is as follows:

[0098] S1. Wellhead Construction Pressure Curve Judgment and Analysis

[0099] Before implementing the multi-stage rubber plugging process, the wellhead construction pressure is assessed based on the obtained wellhead construction pressure curves, and the trend of wellhead construction pressure variation before the implementation of the multi-stage rubber plugging process is estimated. Combining the construction pressure limit of the fracturing equipment and the variation characteristics of the wellhead construction pressure curves, the difference between the construction pressure limit and wellhead construction pressure curves 12a, 12b, and 12c is estimated to clarify the wellhead construction pressure window. The feasibility of the multi-stage rubber plugging process is then determined based on the wellhead construction pressure window.

[0100] If the estimated wellhead construction pressure window is above 10MPa, it is determined that the multi-stage rubber plug temporary plugging process is feasible. The rubber plug temporary plugging process is designed and implemented based on the characteristics of the wellhead construction pressure curve.

[0101] Based on the characteristics of fracturing operation curves in unconventional oil and gas reservoirs, mainly including the three types of wellhead operation pressure curves shown in Figure 2, the main judgments are as follows:

[0102] (1) The wellhead construction pressure is generally stable or fluctuates slightly, such as Figure 2a As shown, when the drilling displacement 13b is stable, the wellhead drilling pressure 12a is generally stable or fluctuates slightly, indicating that the overall natural fractures in the reservoir are underdeveloped and the fracturing fractures are propagating normally. The use of multi-stage rubber plug temporary plugging technology helps to increase the fluid pressure in the fracturing fractures and promote the complexity and uniformity of fracturing fracture propagation.

[0103] (2) After the wellhead construction pressure continuously decreases to a certain level, it basically stabilizes or decreases slightly, such as Figure 2b As shown, when the construction displacement 13b is stable, the wellhead construction pressure curve 12a drops rapidly or drops rapidly and then continues to drop slightly, indicating that the natural fractures in the fracturing reservoir section are well developed, the fracturing fractures have connected to the natural fracture body, and the fluid loss in the fracturing fractures is large. It is necessary to use a temporary plugging process to increase the fluid pressure in the fracturing fractures and increase the complexity and uniformity of the fracturing fractures.

[0104] (3) Wellhead construction pressure rise type, such as Figure 2c As shown. The decision to implement a multi-stage rubber plugging process is based on the difference between the fracturing pressure limit and the wellhead pressure, as well as the increase in wellhead pressure. When the fracturing displacement 13b is stable, the wellhead pressure curve 13a shows a slight upward trend. If the difference between the fracturing pressure limit and the wellhead pressure is greater than 10 MPa, a single rubber plugging can be used to increase the net pressure within the fracture.

[0105] S2, Multi-stage rubber stopper temporary plugging process parameter design

[0106] (1) Stable wellhead construction pressure curve

[0107] If the wellhead construction pressure is stable or fluctuates very little before the rubber plugging process is implemented (as shown in the construction curve) Figure 2a As shown in the diagram, a two-stage rubber plugging technique is employed to temporarily seal the fracture tip and increase the fluid pressure within the fracture. The first-stage rubber plugging process is implemented when 30-40% of the total fracturing fluid volume is used, and the delayed crosslinking slickwater volume is 40-50 ml. 3 A single-stage liquid injection is used to fracture the fracturing fracture. The proppant-sand ratio is designed with one specific ratio, and the proppant addition method is as follows: Figure 2a The proppant addition mode for curve 14c. If 100 / 200 mesh proppant is used, the designed proppant-to-sand ratio is 20-25%; if 70 / 140 mesh proppant is used, the designed proppant-to-sand ratio is 15-20%. After the first-stage rubber plugging process, low-viscosity slickwater + proppant designed for hydraulic fracturing is injected to form the proppant-carrying fluid. The changes in wellhead operating pressure are monitored in real time, and the parameters of the second-stage rubber plugging process are further optimized based on the fluctuation range of the wellhead operating pressure. The second-stage rubber plugging process is implemented when the total fracturing fluid volume is 60-70%. The parameters of the second-stage rubber plugging process are further optimized based on the implementation effect of the first-stage rubber plugging process.

[0108] (2) Wellhead construction pressure curve rapidly decreases and then stabilizes or continues to decrease slightly.

[0109] If the fluid pressure drops rapidly to a certain level before the implementation of the rubber plug temporary plugging process and then stabilizes or continues to drop slightly, it indicates that a certain size of natural fracture has developed in the fracturing section. In this case, a mixture of slickwater and proppant should be used to temporarily plug part of the fracture tip to increase the fluid pressure in the fracturing fracture. For sections with naturally developed fractures, the rubber plug temporary plugging process should be implemented during the stage where the wellhead drilling pressure is relatively stable or continues to drop slightly. Depending on the drilling conditions, a 1-3 stage rubber plug temporary plugging process can be used. If the fluid volume during the stage where the wellhead drilling pressure is stable or drops slightly is less than 30% of the total fluid volume, a 2-stage rubber plug temporary plugging process can be used. The timing for the 1st stage rubber plug temporary plugging is 30-40%, and the preferred volume of delayed cross-linked slickwater is 50-70 ml. 3 The process involves two stages of plug injection, using a sand-addition method as follows: Figure 2bThe proppant addition mode for curve 14c involves high-viscosity slickwater scavenging between the two stages. Considering the characteristics of natural fracture development in the reservoir and the relatively small width of the fracturing fractures, the proppant-to-sand ratio is optimized. If 100 / 200 mesh and 70 / 140 mesh proppant are available on-site, the first stage uses 100 / 200 mesh proppant with a sand ratio of 15-20%, and the second stage uses 40 / 70 mesh proppant with a sand ratio of 20-25%. If only one type of proppant, 100 / 200 mesh or 70 / 140 mesh, is available on-site, a single proppant type is used for temporary plugging with rubber plugs. If 100 / 200 mesh proppant is used, the proppant-to-sand ratio in the first stage is 20-25%, mainly used for temporary plugging of secondary fractures with rubber plugs, and the proppant-to-sand ratio in the second stage is 25-30%, mainly used for temporary plugging of some secondary fractures followed by re-plugging of the main fracture tip. If 70 / 140 mesh proppant is used, the proppant-to-sand ratio in the first stage is 15-20%, mainly using rubber plugs to temporarily seal secondary fractures. The proppant-to-sand ratio in the second stage is 20-25%. The timing for the second-stage rubber plugging is when the total fluid volume is 60-70%. Related construction parameters can be optimized based on the parameters of the first-stage rubber plugging process. If the wellhead pressure drops rapidly by more than 15% and the construction fluid volume is less than 30% of the total designed fracturing fluid volume, the development of natural fractures in the fracturing section is determined by combining reservoir characteristics and the wellhead pressure curve. In this case, the second-stage rubber plugging process uses a three-stage rubber plugging method. If the fluid volume reaches 40-60% of the designed total fluid volume during the stage of stable or slightly decreasing wellhead pressure, a first-stage rubber plugging is performed as needed during this stage, with a preferred fluid volume of 50-70 mg / L. 3 The temporary plugging design is also carried out in two stages. The liquid volume in the first stage is 20-30m³. 3 The liquid volume in the second stage is 30-40m³. 3 The design for adding the proppant is basically similar to that described above.

[0110] (3) Wellhead construction pressure curve rising type

[0111] If the wellhead construction pressure shows an upward trend, the selection of the method for increasing the net pressure within the fracture based on the difference between the fracturing construction pressure limit and the wellhead construction pressure is based on the present invention. If the wellhead construction pressure rises slowly and the difference between the construction pressure limit and the wellhead construction pressure is greater than 10 MPa, a single temporary plugging with a rubber stopper can be selected to increase the net pressure within the fracture. The timing of this process selection is when the total fluid volume is 50-60%. The volume of delayed crosslinking slickwater is 40-50 m³. 3 The proppant addition is completed in one stage, such as... Figure 2c The sand addition pattern is shown in curve 14c. If using 100 / 200 mesh proppant, the proppant-to-sand ratio is 20-25%. If using 70 / 140 mesh proppant, the proppant-to-sand ratio is 15-20%.

[0112] S3, Implementation of Multi-stage Sand Addition Temporary Plugging Process

[0113] After determining that delayed cross-linked slickwater combined with high-sand-ratio, small-particle-size proppant plugs would be used to temporarily increase the fluid pressure within the fracture, a multi-stage plugging process was implemented using fracturing fluid additives and proppant materials from the field. The specific implementation method is as follows:

[0114] ① Delayed crosslinking slickwater preparation. Based on the delayed crosslinking slickwater fracturing fluid formulation, the designed proportions of drag reducers, crosslinking agents, and other additives are pumped into the mixing tank of the sand mixing truck using a slickwater fracturing fluid additive pump, and the delayed crosslinking slickwater is prepared in the mixing tank.

[0115] ② Addition of high-sand-ratio, small-particle-size proppant. During the preparation of delayed crosslinking slickwater, the particle size of the proppant and the sand-to-liquid ratio are selected according to the design parameters of the multi-stage rubber stopper temporary plugging. The proppant of the designed concentration is added to the mixing tank of the sand mixing truck using the stirring cage of the sand mixing truck and then stirred evenly.

[0116] ③ Mixed Fluid Injection. The injection pump of the mixed fluid truck pumps the prepared proppant-carrying fluid (delayed cross-linking slickwater + high-sand-ratio small-particle-size proppant) into the fracturing truck at the designed displacement, forming a high-pressure fluid that is injected into the fracturing fractures of the reservoir. After the delayed cross-linking slickwater achieves complete cross-linking in the reservoir, the liquid viscosity reaches 70-100 mPa·s. The increased viscosity leads to a significant reduction in the filtration loss of the fracturing fluid, achieving the goal of increasing the net pressure of the fracturing fracture and increasing the fracture width. After the net pressure of the fracturing fracture is increased, for some perforation clusters that do not propagate or have a low propagation rate after fracture initiation, the increased net pressure can significantly increase the propagation of this type of perforation cluster and increase the uniformity of fracture propagation. After the high-viscosity cross-linked slickwater carries the high concentration of small-particle-size proppant into the reservoir, the cross-linked slickwater carrying the small-particle-size proppant forms a miscible solid-liquid two-phase rubber plug. During the advancement of the rubber plug mixture, it will block the tip 2 of the secondary fracture and temporarily plug the fracturing fracture region 4, reducing the propagation rate of the original fracturing fracture region 4.

[0117] ④ Displacement after injection of the mixed fluid. After the injection of cross-linked slickwater + high-concentration small-particle-size proppant is completed, the fracturing fluid is converted into low-viscosity slickwater or low-viscosity slickwater carrying proppant. The injection of low-viscosity slickwater promotes the expansion of branch fractures and micro-fractures, increasing the complexity of the fracturing fractures.

[0118] S4. Evaluation of the implementation of multi-stage rubber stopper temporary plugging process

[0119] After implementing a multi-stage rubber plugging process, the increase in wellhead construction pressure after the delayed cross-linked slickwater + high-concentration small-particle-size proppant proppant-carrying fluid enters the reservoir was observed. Simultaneously, the pressure change after low-viscosity slickwater was injected into the formation was observed after the proppant-carrying fluid injection was completed. Furthermore, if real-time monitoring of fracture morphology is conducted using microseismic and / or wide-area electromagnetic methods, the effectiveness of the rubber plugging process can be evaluated using the monitoring results. Subsequently, based on the various changes and monitoring results of the rubber plugging process, the parameters of the subsequent rubber plugging process will be further optimized. After adopting the process of using delayed cross-linked slickwater + high-concentration small-particle-size proppant to form a rubber plug to increase intra-fracture fluid pressure, the effectiveness of the process implementation was evaluated to provide a reference for the process design and implementation of subsequent fracturing stages, and to determine the optimal parameters such as fluid volume, proppant concentration, and proppant quantity suitable for the target well.

[0120] To address the issue of increasing fluid pressure within fractures through temporary plugging during fracturing of unconventional oil and gas reservoirs, this invention employs a method of temporarily plugging with rubber plugs to increase net pressure within the fracture. A multi-stage rubber plugging process is designed for fracturing of unconventional oil and gas reservoirs to promote uniform fracture propagation and increase fracture complexity, thereby improving both fracture uniformity and complexity.

[0121] This invention utilizes a rubber plug to temporarily increase net pressure based on reservoir characteristics, fracturing operation curves, and process requirements. No prior preparation is needed, and the operation can be repeated multiple times to maximize the net pressure within the fracture. Furthermore, the process of increasing net pressure promotes the uniform expansion of multiple fracture clusters and increases the complexity of the fracturing fractures, thereby improving the fracturing effect.

[0122] This invention involves injecting a mixture of delayed cross-linked slickwater and high-concentration small-particle-size proppant into a fracturing reservoir. The delayed cross-linked slickwater significantly reduces fluid loss within the fracture, thereby increasing fluid pressure and fracture width. The high-concentration small-particle-size proppant, when mixed with the delayed cross-linked slickwater, increases its delivery distance within the fracture. The delayed cross-linked slickwater encapsulates the small-particle-size proppant and delivers it to the micro-fractures or fracture tips, forming a temporary plugging effect where ultra-high viscosity slickwater and proppant combine to create a gel plug. This temporarily plugs the existing fracture, reducing its propagation rate and thus increasing fluid pressure within the fracture, promoting uniform fracture propagation, and enhancing fracture complexity. The combined effect of delayed cross-linked slickwater and high-concentration proppant increases fracture fluid pressure, promoting uniform fracture propagation, while the temporary plugging of fracture tips by the small-particle-size proppant promotes fracture deflection, thereby improving fracture uniformity and complexity.

[0123] According to the present invention, a process combining delayed cross-linked high-viscosity cross-linked slickwater and high-concentration small-particle-size proppant is used to improve the net pressure inside the fracture. The overall process is simple and easy to operate. On-site, only the delayed cross-linked slickwater fracturing fluid needs to be prepared online using a sand mixing truck, and then injected into the reservoir fracture with the addition of high-concentration small-particle-size proppant to achieve the improvement of the net pressure inside the fracture.

[0124] This invention proposes a multi-stage temporary plugging process to increase fluid pressure in fracturing fractures and temporarily plug part of existing fracturing fractures, primarily targeting large-scale slickwater volumetric fracturing in unconventional oil and gas reservoirs. The fracturing fluid system used in on-site fracturing is an integrated viscosity-modifying slickwater system. The drag-reducing agent in this integrated viscosity-modifying slickwater can form delayed crosslinking slickwater with a delayed crosslinking agent. The crosslinking time can be adjusted according to the formula to ensure that the delayed crosslinking slickwater fully crosslinks to form ultra-high viscosity slickwater after entering the fracturing fracture. At the fracturing site, a fracturing mixing truck and a small-volume pump are used to inject high-concentration drag-reducing agent and crosslinking agent to form delayed crosslinking slickwater. After complete crosslinking, the viscosity of the slickwater ranges from 70-100 mPas. This ultra-high viscosity crosslinked slickwater significantly reduces fluid loss and increases fracture width after entering the reservoir.

[0125] To address the field requirements of temporary plugging within fractured reservoirs, increasing fluid pressure in fracturing fractures, promoting uniform fracture propagation, and improving fracture complexity, this invention proposes a process using a combination of delayed cross-linked slickwater and high-concentration small-particle-size proppant to form a rubber plug. This two-phase rubber plug, used to temporarily plug fracture tips or micro-fractures, promotes the formation of complex fracturing fractures. The multi-stage rubber plugging process utilizes existing integrated variable-viscosity slickwater fracturing fluid and proppant for targeted pumping design and construction. A mixed rubber plug is formed by the delayed cross-linked liquid and high-concentration small-particle-size proppant particles. Once inside the fracturing fracture, this mixed plug reduces fluid loss, temporarily plugs micro-fractures and fracture tips, thereby increasing fluid pressure within the fracture and slowing the propagation rate of existing fractures. This promotes uniform fracture propagation and increases fracture complexity. The present invention provides a process for temporarily plugging fluid pressure within a fracture using a liquid-solid two-phase rubber plug. The plugging materials are simple and readily available, the construction process is simple and inexpensive, and multiple stages of the plugging process can be implemented on-site as needed to maximize the fluid pressure within the fracture and promote the formation of complex hydraulic fracturing fractures.

[0126] The construction flow rate of this invention adopts the pump injection program flow rate designed in the original fracturing scheme, without the need for separate construction flow rate design for temporary plugging. This ensures that the delayed cross-linking slickwater can carry the high sand ratio, small particle size proppant to the tip of the fracturing fracture and the location of the fracturing microfracture, preventing the high sand ratio proppant from settling in the near-wellbore fracture and affecting the temporary plugging effect. Secondly, it facilitates wellhead construction pressure observation, ensuring that changes in wellhead construction pressure can be easily compared and observed after the high-concentration, small particle size proppant-carrying fluid enters the reservoir.

[0127] The process described needs to be selected based on the relationship between the overall wellhead construction pressure and the pressure limit of the on-site construction equipment. The difference between the construction pressure limit and the fracturing wellhead construction pressure should be at least greater than 10 MPa to ensure that the wellhead construction pressure will not exceed the construction pressure limit after the temporary plugging process causes the fluid pressure inside the fracture to rise, thus ensuring construction safety.

[0128] The rubber plugging process of the present invention increases the fluid pressure in the fracturing fracture by combining delayed cross-linked slickwater and high sand ratio small particle size proppant. No other plugging materials need to be added during the process, and the process does not produce secondary reservoir pollution similar to that of polymer plugging agents.

[0129] The temporary plugging process of this invention requires selection of the timing and process parameters for temporary plugging based on changes in wellhead construction pressure and construction conditions before temporary plugging. Generally speaking, the process of increasing fluid pressure within the fracture through temporary plugging is chosen during the proppant-carrying stage of fracturing operations. After injecting a certain amount of fracturing fluid and proppant into the unconventional oil and gas reservoir, the temporary plugging process is implemented to achieve temporary plugging of the fracturing fractures in the unconventional oil and gas reservoir.

[0130] The method of this invention is applicable not only to matrix-type and fractured shale and tight sandstone reservoirs, and to coalbed methane reservoirs, but also to unconventional oil and gas reservoirs at different depths, including shallow and deep unconventional oil and gas reservoirs.

[0131] A second aspect of the present invention provides the application of the aforementioned method in unconventional oil and gas reservoirs, such as shale oil / gas reservoirs, tight sandstone gas reservoirs, or coalbed methane reservoirs.

[0132] The method of this invention can be applied to various reservoir types such as shale, tight sandstone and coalbed methane, to enhance the fracturing effect.

[0133] The present invention will be described in detail below through examples. Unless otherwise specified in the following examples and comparative examples, conditions were performed under conventional conditions or conditions recommended by the manufacturer. Reagents or instruments used, unless otherwise specified, are all commercially available products.

[0134] The following is a detailed implementation description and comparison for the fracturing phase where the wellhead construction pressure curve rapidly decreases to a certain extent and then stabilizes.

[0135] Comparative Example

[0136] For the fracturing section where the wellhead construction pressure curve rapidly declines to a certain level and then stabilizes, temporary plugging is typically achieved by dropping temporary plugging balls and temporary plugs. The designed construction displacement is increased to 20m³. 3 At a rate of [insert value here] / min, the wellhead construction pressure rapidly decreased from 97.2 MPa to 82.1 MPa, with a slight downward trend continuing. Based on the construction design, at 45.2 minutes of construction time, 150 kg of 20 / 70 mesh soluble temporary plugging agent was added for the first time, along with 40 / 70 mesh quartz sand. After adding the temporary plugging agent, the construction pressure increased by 4.97 MPa. As the fracturing operation continued, the wellhead construction pressure continued to decrease, indicating that the temporary plugging effect of the agent gradually diminished. During this stage, the overall construction pressure increased by 1.2 MPa compared to before the addition of the temporary plugging agent. At 86.5 minutes of operation, 36 18-22mm soluble plugging balls were deployed. After reaching the bottom of the well, the perforation holes were temporarily plugged. Following the deployment, the wellhead operating pressure reached a maximum of 90.1 MPa, compared to 80.3 MPa before the deployment, representing an initial pressure increase of 9.8 MPa. However, as operation continued, the operating pressure steadily decreased to 87.3 MPa, resulting in an average increase of 7.4 MPa after the deployment. At 101.5 minutes, a second deployment of 150 kg of 20 / 70 mesh plugging agent was performed. Upon entering the formation, the pressure increased by 1.45 MPa, but then gradually decreased to 84.55 MPa, with an average decrease of 0.55 MPa. The second deployment showed a less effective plugging effect. The operation curve for the temporary plugging fracturing operation is shown below. Figure 4a As shown.

[0137] A total of 36 temporary plugging balls and 300 kg of temporary plugging agent were used in this operation. The first plugging with the agent resulted in an overall pressure increase of 1.2 MPa, the plugging with the balls resulted in a pressure increase of 7.4 MPa, and the second plugging with the agents resulted in a pressure decrease of 0.55 MPa. Overall, the first plugging with the agents and the balls were effective, but the second plugging was less effective. The cost of a single plugging ball and agent is approximately 25,000-30,000 yuan. Generally, a single well has more than 20 fracturing stages, and the cost of temporary plugging materials for a single well is 500,000-600,000 yuan. Furthermore, the temporary plugging agent and balls may not completely dissolve during the operation, and the resulting residue may contaminate the fractures, affecting the fracturing effect.

[0138] Example

[0139] For a fracturing section where the wellhead pressure curve rapidly declines to a certain level and then stabilizes, the rubber plug temporary plugging process of this invention is utilized. The specific implementation is as follows: The fracturing time is 42.9 minutes. 20m of a proppant-carrying fluid consisting of delayed cross-linked slickwater and 20% 70 / 140 mesh quartz sand is used. 3 Then, low-viscosity slickwater was used for scavenging, followed by the injection of 30m of a sand-carrying solution consisting of delayed crosslinking slickwater and 24% 70 / 140 mesh quartz sand. 3 After the sand-carrying fluid entered the reservoir fracture, the construction pressure increased by 72 MPa, and the overall construction pressure increased by 2.85 MPa, which is higher than the 1.20 MPa of the previous conventional temporary plugging. The construction time was 76.2 minutes. The second time, a 40m... 3 Delayed crosslinking slickwater + 20% 70 / 140 mesh quartz sand resulted in a maximum increase of 10.2 MPa in construction pressure and an overall increase of 6.5 MPa. The construction time was 106.3 minutes, involving the addition of 40m³ of a sand-carrying solution containing delayed crosslinking slickwater + 20% 40 / 70 mesh ceramsite proppant. 3 The maximum construction pressure increase was 7.1 MPa, and the average increase was 3.1 MPa. The overall construction curve of the fracturing section is shown below. Figure 4b As shown.

[0140] By comparison Figure 4a and Figure 4b It can be seen that the pressure increase from the rubber plugging process in this embodiment of the invention is greater than that from ball-feeding and agent-feeding temporary plugging. Meanwhile, the 70 / 140 mesh quartz sand and 40 / 70 mesh ceramsite used in this embodiment of the invention can support fractures after entering the formation. Compared with conventional low-viscosity or medium-viscosity slickwater, delayed cross-linking slickwater increases the cost by approximately 60-80 yuan / m³. 3 The cost of this invention increases by 7,500-10,000 yuan per segment. Based on 20 segments of fracturing per well, the cumulative cost increases by 150,000-200,000 yuan. Meanwhile, this invention eliminates the need for additional temporary plugging materials, preventing additional pollution to the reservoir fracturing fractures and avoiding any impact on their conductivity.

[0141] The results above show that the rubber plug temporary plugging process of the present invention has significantly better effects in terms of increasing construction pressure and net fracture pressure, and temporarily plugging fracturing fractures. At the same time, the cost of the rubber plug temporary plugging process of the present invention is relatively low and will not cause additional reservoir contamination that affects the fracturing effect.

[0142] The foregoing has described a preferred embodiment of the present invention in detail; however, the present invention is not limited thereto. Within the scope of the inventive concept, various simple modifications can be made to the technical solution of the present invention, including combining the various technical features in any other suitable manner. These simple modifications and combinations should also be considered as the content disclosed in the present invention and are all within the protection scope of the present invention.

Claims

1. A reservoir fracturing method, characterized in that, The method includes the following steps: (1) Classify the wellhead construction pressure curves; among them, the wellhead construction pressure curves that show a stable or slightly fluctuating trend are Class I curves, the wellhead construction pressure curves that show a downward trend and then show a basically stable or continuously downward trend after a certain decline are Class II curves, and the wellhead construction pressure curves that show an upward trend and the difference between the construction pressure limit and the wellhead construction pressure is above 10MPa are Class III curves. (2) Different rubber plugging processes are used for the above different types of curves to inject delayed cross-linked slickwater and small-particle-size proppant into the fracturing fracture to form a solid-liquid two-phase mixture rubber plug; wherein, for type I curves, a first rubber plugging process is used; the first rubber plugging process uses a 2-stage rubber plugging process; for type II curves, a second rubber plugging process is used; the second rubber plugging process uses a 1-3 stage rubber plugging process; for type III curves, a third rubber plugging process is used; the third rubber plugging process uses a 1-stage rubber plugging process. (3) Subsequent injection of low-viscosity slickwater or low-viscosity slickwater carrying sand fluid to replace the formed rubber plugs in the micro-cracks and crack tip regions of the fracturing fracture, thereby improving the uniformity and complexity of the fracturing fracture; wherein, the viscosity of the delayed crosslinking slickwater after complete crosslinking is 70-100 mPa.s, and the viscosity of the low-viscosity slickwater or low-viscosity slickwater carrying sand fluid is 3-5 mPa.s.

2. The method according to claim 1, wherein, In Type I curves, the pressure fluctuation range of the wellhead construction pressure curve is within 2.5% of the average pressure of the stage construction, and the pressure difference at the wellhead construction is within 3-5 MPa. And / or, in Type II curves, the wellhead construction pressure curve shows a rapid decrease to a certain extent followed by a basic stabilization or a continuous downward trend, the decrease in wellhead construction pressure value exceeds 10%, the rate of decrease in wellhead construction pressure exceeds 7.5 MPa / min, and the decrease in wellhead construction pressure value is greater than 10 MPa; or, the rate of decrease in wellhead construction pressure is 1-5 MPa / min, and the overall decrease in wellhead construction pressure value is greater than 5 MPa. And / or, in the Type III curve, the rise in wellhead construction pressure is less than 1 MPa / min, and the difference between the construction pressure limit and the wellhead construction pressure is greater than 10 MPa, preferably 10-15 MPa.

3. The method according to claim 1 or 2, wherein, The small-particle-size proppant is at least one of 100 / 200 mesh proppant, 70 / 140 mesh proppant, and 40 / 70 mesh proppant; Preferably, the small-particle-size proppant is ceramsite and / or quartz sand.

4. The method according to any one of claims 1-3, wherein, The threshold values ​​for increasing wellhead construction pressure after using the rubber plug temporary plugging process are as follows: First threshold range: Wellhead construction pressure increase > 5 MPa; Second threshold range: 3MPa ≤ wellhead construction pressure increase value ≤ 5MPa; The third threshold range: wellhead construction pressure increase value < 3MPa.

5. The method according to claim 4, wherein, In the first rubber plug temporary plugging process, the timing of the first-stage rubber plug temporary plugging is 30-40% of the total fluid volume of the fracturing design, and the timing of the second-stage rubber plug temporary plugging is 60-70% of the total fluid volume of the fracturing design.

6. The method according to claim 4 or 5, wherein, In the first rubber stopper temporary plugging process, the volume of delayed cross-linking slickwater for the first-stage rubber stopper temporary plugging is 40-50m³. 3 ; If the wellhead working pressure increases to the first threshold after the first-stage rubber plug temporary plugging, the volume of delayed cross-linking slickwater from the second-stage rubber plug temporary plugging will be 30-40 m³. 3 ; If the wellhead working pressure increases to the second threshold after the first-stage rubber plug temporary plugging, the volume of delayed cross-linking slickwater in the second-stage rubber plug temporary plugging process is 40-50m³. 3 ; If the wellhead working pressure increases to the third threshold after the first-stage rubber plug temporary plugging, the volume of delayed cross-linking slickwater from the second-stage rubber plug temporary plugging is 50-60m³. 3 .

7. The method according to any one of claims 4-6, wherein, In the first rubber stopper temporary plugging process, the first-stage rubber stopper temporary plugging uses 100 / 200 mesh proppant with a proppant sand ratio of 20-25%, and sand is added in one continuous sand ratio; or, the first-stage rubber stopper temporary plugging uses 70 / 140 mesh proppant with a proppant sand ratio of 15-20%. If the wellhead construction pressure increases to the first threshold after the first stage of rubber plug temporary plugging, the second stage of rubber plug temporary plugging uses 100 / 200 mesh proppant, and the proppant-to-sand ratio is reduced to 15-18%; or, the second stage of rubber plug temporary plugging uses 70 / 140 mesh proppant, and the proppant-to-sand ratio is reduced to 13-15%. If the wellhead construction pressure increases to the second threshold after the implementation of the first-stage rubber plug temporary plugging, the proppant and sand ratio used for the second-stage rubber plug temporary plugging shall be the same as those used for the first-stage rubber plug temporary plugging. If the wellhead construction pressure increases to the third threshold after the first stage of rubber plug temporary plugging, the second stage of rubber plug temporary plugging uses 40 / 70 mesh proppant with a sand ratio of 20-25%.

8. The method according to claim 4, wherein, In the second rubber plug temporary plugging process, if the amount of construction fluid is less than 30% of the total fracturing design fluid volume during the stage of basically stable wellhead construction pressure or the stage of slight decrease, the second rubber plug temporary plugging adopts a two-stage rubber plug temporary plugging. The timing of the first stage rubber plug temporary plugging is 30-40% of the total fracturing construction fluid volume; the timing of the second stage rubber plug temporary plugging is 60-70% of the total fracturing construction fluid volume. Preferably, the volume of the delayed cross-linking slickwater temporarily plugged by the first-stage rubber stopper is 50-70 m³. 3 The process involves two stages of rubber stopper injection. The first stage involves a liquid volume of 20-30 ml. 3 The liquid volume in the second stage is 30-40m³. 3 ; If the wellhead working pressure increases to the first threshold after the first-stage rubber plug temporary plugging, the delayed cross-linking slickwater volume of the second-stage rubber plug temporary plugging process is 30-40m³. 3 ; If the wellhead construction pressure increases to the second threshold after the implementation of the first-stage rubber plug temporary plugging, refer to the volume of delayed cross-linking slickwater of the first-stage rubber plug temporary plugging. If the wellhead construction pressure increases to the third threshold after the first-stage rubber plugging, the volume of delayed cross-linked slickwater in the second-stage temporary plugging fracturing process is 40-50 m³. 3 .

9. The method according to claim 8, wherein, In the second rubber stopper temporary plugging process, the first stage of the first-stage rubber stopper temporary plugging uses 100 / 200 mesh proppant with a proppant-to-sand ratio of 15-20%; the second stage uses 70 / 140 mesh proppant with a proppant-to-sand ratio of 20-25%; or, the first stage of the first-stage rubber stopper temporary plugging uses 100 / 200 mesh proppant with a proppant-to-sand ratio of 20-25%; the second stage uses 100 / 200 mesh proppant with a proppant-to-sand ratio of 25-30%; or, the first stage uses 70 / 140 mesh proppant with a proppant-to-sand ratio of 15-20%; the second stage uses 70 / 140 mesh proppant with a proppant-to-sand ratio of 20-25%. For the second-stage rubber plugging, 40 / 70 mesh proppant is used. If the wellhead pressure after the first-stage rubber plugging reaches the first threshold, the proppant-to-sand ratio is 15-20%; if the wellhead pressure after the first-stage rubber plugging reaches the second threshold, the proppant-to-sand ratio is 18-22%; if the wellhead pressure after the first-stage rubber plugging reaches the third threshold, the proppant-to-sand ratio is 20-25%.

10. The method according to claim 4, wherein, In the second rubber plug temporary plugging process, if the fluid volume during the wellhead construction pressure basically stabilizes or decreases slightly reaches 40-60% of the designed total fluid volume, the second rubber plug temporary plugging process adopts the first-level rubber plug temporary plugging, and the temporary plugging time is 65-70% of the total fluid volume of fracturing construction. Preferably, the volume of the delayed cross-linking slickwater temporarily plugged by the first-stage rubber stopper is 50-70 m³. 3 The process involves two stages of injection to form the rubber stopper. In the first stage, the liquid volume is 20-30 ml. 3 The liquid volume in the second stage is 30-40m³. 3 ; More preferably, the first stage uses 70 / 140 mesh proppant with a proppant-to-sand ratio of 20-25%; the second stage uses 40 / 70 mesh proppant with a proppant-to-sand ratio of 20-25%.

11. The method according to claim 4, wherein, In the second rubber plug temporary plugging process, if the wellhead construction pressure drops rapidly and the drop exceeds 15% and the construction fluid volume is less than 30% of the total fracturing fluid volume designed, the development of natural fractures in the fracturing section is determined by combining reservoir characteristics and wellhead construction pressure curve. The second rubber plug temporary plugging process adopts three-stage rubber plug temporary plugging. The timing of the first-stage rubber plug temporary plugging is 30-35% of the total fracturing fluid volume, the timing of the second-stage rubber plug temporary plugging is 50-60% of the total fluid volume, and the timing of the third-stage rubber plug temporary plugging is 70-75% of the total fluid volume. Preferably, the volume of the delayed cross-linking slickwater temporarily plugged by the first-stage rubber stopper is 50-70 m³. 3 The process is implemented in two stages; the volume of the delayed cross-linking slickwater temporarily plugged in the second stage is 40-50 m³. 3 The volume of delayed cross-linking slickwater temporarily plugged by the third-stage rubber stopper is 30-40 m³. 3 ; More preferably, the first-stage rubber plug temporary plugging uses 100 / 200 mesh proppant, the proppant sand ratio in the first stage is 20-25%, and the proppant sand ratio in the second stage is 25-30%; or, the first-stage rubber plug temporary plugging uses 70 / 140 mesh proppant, the proppant sand ratio in the first stage is 15-20%, and the proppant sand ratio in the second stage is 20-25%. For the second-stage rubber plugging, 100 / 200 mesh or 70 / 140 mesh proppant is used. If the wellhead pressure increase after the first-stage rubber plugging reaches the first threshold, the proppant-to-sand ratio is 15-20%; if the wellhead pressure increase after the first-stage rubber plugging reaches the second threshold, the proppant-to-sand ratio is 18-20%; if the wellhead pressure increase after the first-stage rubber plugging reaches the third threshold, the proppant-to-sand ratio is 20-25%. For the third-stage rubber plug, 40 / 70 mesh proppant is used. If the wellhead pressure increases to the first threshold after the second-stage rubber plug, the proppant-to-sand ratio is 15-20%; if the wellhead pressure increases to the second threshold after the second-stage rubber plug, the proppant-to-sand ratio is 18-22%; if the wellhead pressure increases to the third threshold after the second-stage rubber plug, the proppant-to-sand ratio is 20-25%.

12. The method according to any one of claims 1-11, wherein, In the third rubber plug temporary plugging process, the timing of the first-stage rubber plug temporary plugging is 50-60% of the total fluid volume during fracturing operations; Preferably, the volume of the delayed cross-linking slickwater temporarily plugged with a stage 1 rubber stopper is 40-50 m³. 3 ; Preferably, the primary rubber plug is temporarily plugged with 100 / 200 mesh proppant, and the proppant sand ratio is 20-25%; or, 70 / 140 mesh proppant is used, and the proppant sand ratio is 15-20%.

13. The application of the method as described in any one of claims 1-12 in shale oil / gas reservoirs, tight sandstone gas reservoirs or coalbed methane reservoirs.

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