Method for achieving universe supporting of unconventional reservoir fracturing crack proppant
By optimizing the classification of fracture patterns and construction parameters in unconventional reservoirs, the problem of proppant settlement in cracks is solved, and the overall support of proppant and the improvement of oil and gas reservoir mining efficiency is achieved.
Patent Information
- Application Number
- CN202411966226.7
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Filing Date
- 2024-12-30
- Publication Date
- 2025-05-02
AI Technical Summary
In unconventional reservoirs, low viscosity slippery water fracturing fluid causes the proppant to settle rapidly in the cracks and cannot be effectively laid, resulting in insufficient support and affecting the mining efficiency of oil and gas reservoirs.
By classifying the reservoir fracture morphology and designing appropriate resistance reducing agent, fiber and proppant parameters according to different categories, the construction parameter optimization is performed using the crack expansion numerical simulation software based on the phase field method to improve the laying effect of proppant.
The whole-region support of proppant in unconventional reservoirs is achieved, and the support effect in the length and height direction of the cracks is improved, thereby improving the mining efficiency of oil and gas reservoirs.
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Figure CN119914238A_ABST
Abstract
Description
Technical Field
[0001] The present invention relates to the technical field of oil and gas development, and in particular to a method for achieving full-area support of proppant for unconventional reservoir fracturing. Background Art
[0002] Large-scale slickwater hydraulic fracturing technology is an important means of exploiting oil and gas resources in unconventional reservoirs represented by shale oil and gas reservoirs and tight oil and gas reservoirs. It has also been widely used in the exploitation of unconventional oil and gas reservoirs at home and abroad.
[0003] Large-scale slickwater hydraulic fracturing refers to the use of a fracturing pump truck to pump a low-viscosity slickwater liquid with drag reduction properties (usually the viscosity of slickwater in tight gas fracturing is several to tens of millipascals seconds, while the viscosity of slickwater in shale gas fracturing is less than 5mPa·s) and a solid-liquid two-phase mixture of proppant particles at a large displacement (the main construction displacement on site is about 10 to 20m 3 / min) is injected into the formation to form a relatively complex fracture morphology in the reservoir, thereby controlling a larger volume of recoverable oil and gas reserves. However, due to the low viscosity of slick water, even under large pumping conditions, the proppant will quickly settle to the bottom of the hydraulic fractures created by fracturing and form a compact proppant sand bank (the volume concentration of the proppant is about 60%), resulting in a smaller height and length of the proppant in the fracture (Tao Zhang, Ruoyu Yang, Jianchun Guo, Jie Zeng. Numerical Investigation on Proppant–Water Mixture Transport in Slot under High Reynolds Number Conditions[J]. Energies, 2020, 21).
[0004] Fiber is a commonly used auxiliary material in hydraulic fracturing. On the one hand, adding fiber can help fracturing fluid to move proppant to a longer distance (Ma Jian. Research on the mechanism of fiber-assisted sand carrying in channel fracturing [D]. Southwest Petroleum University, 2017). In particular, the fiber and the macromolecular chain of fracturing fluid in high-viscosity fracturing fluid can work together to maintain the integrity of the proppant group during the transportation process in the fracture, and finally form columnar support in the fracture (Guo Jianchun, Ma Jian, Zhang Tao, Zhao Zhihong, Yang Ruoyu. Experimental study on factors affecting the morphology of flow channels in channel fracturing [J]. Oil and Gas Geology and Recovery, 2017, 24(05)). On the other hand, fiber plays a role of "reinforcement" in the proppant sand pile, and can prevent proppant backflow to a certain extent during proppant flowback and production after fracturing (Zheng Ping, Zou Yifeng. Research on proppant backflow mechanism and sand control technology in horizontal gas wells [D]. Oil and Gas Reservoir Evaluation and Development, 2012, 2(06)). Judging from the current field applications, fiber has become a very important auxiliary material in the hydraulic fracturing process.
[0005] However, when large-scale slickwater fracturing is used in unconventional reservoirs, the viscosity of the slickwater fracturing fluid is low, and there are no large molecular chains at the microscopic level. If a low concentration of fiber is added during the construction process, the distribution characteristics of the fiber in the fracturing fluid belong to the dilute phase. Due to the lack of the joint action of the high-viscosity fracturing fluid macromolecular chains, it is difficult for the fibers themselves to overlap each other to form a network structure. Therefore, the fiber cannot play a role in maintaining the integrity of the proppant or proppant group during its transportation process. At the same time, since the probability of the fiber and the proppant acting in a collision manner is also very small, it cannot interfere with the sedimentation behavior of the proppant. If the concentration of fiber added during the construction process is too high, although the fiber can theoretically assist the sand carrying effect of the proppant, when the fiber-proppant-fracturing fluid passes through the perforation holes and the branch seam entrance, it is easy to cause the holes to be blocked and the cracks to be blocked, which brings construction risks.
[0006] Therefore, how to make full use of the advantages of fiber to overcome the insufficient support of fracture proppants in unconventional oil and gas reservoirs, thereby increasing the effective fracture support volume, is a technical problem that urgently needs to be solved in the current unconventional reservoir reconstruction. Summary of the invention
[0007] In order to improve the filling effect of proppant and fiber in the fracture, the technical solution adopted by the present invention is:
[0008] A method for achieving full-area propping of unconventional reservoir fracturing fracture proppant, characterized by comprising the following steps:
[0009] 1) For the unconventional reservoir to be transformed, basic parameters are collected and a reservoir geological model is established based on the basic parameters;
[0010] 2) Simulate fracture propagation based on fracturing design parameters to obtain fracture morphology produced by fracturing in unconventional reservoirs;
[0011] 3) Classifying the cracks into main cracks, primary cracks, and secondary cracks and above according to the crack morphology, and calculating the volume ratio of each type of cracks;
[0012] 4) Unconventional reservoirs are divided into Class I, Class II, and Class III according to the volume ratio of each type of fracture, and the parameters of the drag reducing agent, fiber, and proppant are designed to carry out fracturing construction.
[0013] Preferably, crack propagation numerical simulation software based on the phase field method is used to simulate crack propagation.
[0014] Preferably, the first-level secondary seam is a secondary seam other than the main seam and has a seam width greater than 1 mm, and the second-level and above secondary seams are secondary seams with a seam width less than 1 mm.
[0015] Preferably, the first category is a reservoir in which the main fracture volume after transformation accounts for more than 95% of the total fracture volume, the second category is a reservoir in which the main fracture volume after transformation accounts for more than 75% and less than 95%, and the third category is a reservoir in which the main fracture volume after transformation is less than 70%.
[0016] Preferably, for Class I reservoirs, the concentration of the drag reducing agent is 0.3%-0.6% of the liquid volume, and the concentration of the fiber stabilizer is 0.2%-0.4% of the liquid volume; for Class II reservoirs, the concentration of the drag reducing agent is 0.2%-0.5% of the liquid volume, and the concentration of the fiber stabilizer is 0.2%-0.5% of the liquid volume; for Class III reservoirs, the concentration of the drag reducing agent is 0.1%-0.3% of the liquid volume, and the concentration of the fiber stabilizer is 0.2%-0.6% of the liquid volume.
[0017] Preferably, for a type of reservoir, a fiber with a length of 6 mm to 9 mm is selected, the fiber addition amount is 0.4% to 1.2% of the proppant mass, and the proppant type is 70-140 mesh silt sand and 40-70 mesh or 30-50 mesh proppant;
[0018] For the second type of reservoir, the fiber length is 6 mm or 9 mm, the fiber addition amount is 0.4%-1.2% of the proppant mass, and the proppant types are 100-200 mesh micro proppant, 70-140 mesh silt sand, and 40-70 mesh or 30-50 mesh proppant;
[0019] For the three types of reservoirs, fibers with a length of 3 mm to 6 mm were selected, the fiber addition amount was 0.4% to 0.8% of the proppant mass, and the proppant types were 100-200 mesh microproppant, 70-140 mesh silt sand, and 40-70 mesh or 30-50 mesh proppant.
[0020] Preferably, the mass ratio of 70-140 mesh to 40-70 mesh or 30-50 mesh proppant in a reservoir is 7:3 to 1:0;
[0021] For the second type of reservoir, the mass ratio of 100-200 mesh and 70-140 mesh to 40-70 mesh or 30-50 mesh proppant is 7:3 to 1:0;
[0022] For the three types of reservoirs, the mass ratio of 100-200 mesh and 70-140 mesh to 40-70 mesh or 30-50 mesh proppant is 7:3 to 1:0.
[0023] Preferably, the ratio between 100-200 mesh and 70-140 mesh increases with the complexity of the cracks, and the number of 100-200 mesh particles increases.
[0024] Preferably, for a type of reservoir, 70-140 mesh silt mixed with 6 mm fiber is pumped into the formation at the initial and middle stages of fracturing, and in the later stages of construction, 40-70 mesh or 30-50 mesh proppant and 6 mm or 9 mm fiber are mixed and injected into the formation;
[0025] For Class II reservoirs, at the initial and intermediate stages of fracturing, 100-200 mesh microproppant and 70-140 silt sand are mixed, 6 mm fiber is added, and pumped into the formation. At the later stage of fracturing construction, 40-70 mesh or 30-50 mesh proppant and 6 mm or 9 mm fiber are mixed and pumped into the formation.
[0026] For the three types of reservoirs, in the initial and intermediate pumping stages of fracturing, 100-200 mesh microproppant and 70-140 silt sand are mixed, 3mm fiber is added, and pumped into the formation. In the later stage of fracturing construction, 40-70 mesh or 30-50 mesh proppant and 6mm fiber are mixed and pumped into the formation.
[0027] On the other hand, the present invention provides a device for achieving full-area support of proppant in unconventional reservoir fracturing fractures, characterized in that it includes: at least one processor and a memory communicatively connected to the processor; the memory stores instructions executable by the processor, and the instructions are executed by at least one processor so that the at least one processor can execute any of the calculation methods described above.
[0028] On the other hand, the present invention provides a computer-readable storage medium having a computer program stored thereon, wherein the computer program implements the steps of any of the above methods when executed by a processor.
[0029] In summary, the present invention proposes a method for achieving full-area support of proppant in unconventional reservoir fracturing fractures. The present invention fully utilizes the ability of fibers and stabilizers to assist in carrying sand, classifies the reservoir fracture morphology and formulates corresponding fracturing design parameters to increase the degree of proppant laying in the length and height directions of the hydraulic fractures, thereby achieving full-area support of proppant in unconventional reservoir fracturing fractures. BRIEF DESCRIPTION OF THE DRAWINGS
[0030] Figure 1 It is a schematic diagram of the method flow of the present invention;
[0031] Figure 2 This is a crack morphology diagram of the 8th section in an embodiment of the present invention;
[0032] Figure 3 The proppant laying forms in the fractures at different time points in the embodiments of the present invention;
[0033] Figure 4 This is the proppant laying form in the conventional slick water-carrying sand fracture in the embodiment of the present invention;
[0034] Figure 5 This is a diagram of the cluster structure formed by fiber-stabilizer-fracturing fluid-proppant in an embodiment of the present invention. DETAILED DESCRIPTION
[0035] The present invention will be described in detail below in conjunction with the accompanying drawings.
[0036] In order to make the purpose, technical solution and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are only used to explain the present invention and are not used to limit the present invention.
[0037] The prior art uses fibers and proppants to fill fractures, but the supporting effect is poor. Based on this, the present invention provides a method for achieving full-area support of proppants in unconventional reservoir fracturing fractures, which mainly includes the following steps:
[0038] 1) For the unconventional reservoir to be transformed, basic parameters are collected and a reservoir geological model is established based on the basic parameters.
[0039] For the reservoirs that need to be transformed, their basic parameters are collected to establish the corresponding geological model. The basic parameters include reservoir geology and mechanical parameters. Specifically, they also include river channel width, reservoir thickness, reservoir rock mechanical parameters, permeability, oil and gas reservoir pressure, porosity, gas content, heterogeneity and other parameters.
[0040] 2) Perform fracture propagation simulation based on fracturing design parameters to obtain the fracture morphology produced by fracturing in unconventional reservoirs.
[0041] Further, in combination with the basic parameters collected in step 1), according to the segmentation and perforation methods given in the fracturing design, and the corresponding construction parameters, the fracture extension numerical simulation software can be used to simulate the fracture extension during the construction process of the established reservoir geological model to obtain the complex fracture morphology produced by the unconventional reservoir fracturing. Those skilled in the art can select commercial software or self-developed software according to actual needs. In a preferred embodiment, a fracture extension numerical simulation software based on the phase field method can be selected.
[0042] 3) According to the crack morphology, the cracks are divided into main cracks, primary secondary cracks, secondary secondary cracks and above, and the volume ratio of each type of cracks is calculated.
[0043] According to the crack morphology obtained by simulating crack expansion, the cracks are divided into main cracks, first-level secondary cracks and second-level and above secondary cracks.
[0044] The main crack refers to one or more relatively large cracks in the expansion form, the first-level secondary crack is a secondary crack other than the main crack and with a width greater than 1mm, and the second-level and above secondary cracks are secondary cracks with a width less than 1mm. The volume ratios of the main crack, the first-level secondary crack, and the second-level and above secondary cracks are obtained by statistics. Relatively speaking, in the same crack, the smaller the crack width, the greater its relative distance from the hole.
[0045] 4) Unconventional reservoirs are divided into Class I, Class II, and Class III according to the volume ratio of each type of fracture, and the parameters of the drag reducing agent, fiber, and proppant are designed to carry out fracturing construction.
[0046] Specifically, the first category is the reservoir whose main fracture volume accounts for more than 95% of the total fracture volume after transformation. This type of reservoir generally has the characteristics of large geostress, undeveloped natural fractures, and strong reservoir homogeneity, and it is difficult to form complex fractures during the fracturing process. The second category is the reservoir whose main fracture volume exceeds 75% and is less than 95% after transformation. This type of reservoir generally represents that some of the conditions such as geostress, natural fractures and reservoir heterogeneity meet the requirements for the formation of complex fractures, but no highly complex fracture morphology is formed during the fracturing process. The third category is the reservoir whose main fracture volume is less than 70% after transformation. This type of reservoir represents that geostress, natural fractures and reservoir heterogeneity meet the requirements for the formation of complex fractures, and the construction parameters cooperate with them to produce complex fractures during the fracturing process.
[0047] According to the classification results of unconventional reservoirs, the concentrations of the drag reducing agent (to adjust the viscosity of slick water) and fiber stabilizer used are determined. For the first type of reservoirs in the above classification, the amount of drag reducing agent added is 0.3%-0.6% of the liquid volume, and the amount of fiber stabilizer added is 0.2%-0.4% of the liquid volume; for the second type of reservoirs, the amount of drag reducing agent added is 0.2%-0.5% of the liquid volume, and the amount of fiber stabilizer added is 0.2%-0.5% of the liquid volume; for the third type of reservoirs, the amount of drag reducing agent added is 0.1%-0.3% of the liquid volume, and the amount of fiber stabilizer added is 0.2%-0.6% of the liquid volume.
[0048] Furthermore, according to the classification results of unconventional reservoirs, the properties of the fibers and proppants used are determined. For a type of reservoir, fibers with a length of about 6mm-9mm are selected, and the fiber addition amount is 0.4%-1.2% of the proppant mass; the proppant types are 70-140 mesh silt sand and 40-70 mesh or 30-50 mesh proppant, of which the mass ratio of 70-140 mesh to 40-70 mesh or 30-50 mesh proppant is 7:3 to 1:0.
[0049] For Class II reservoirs, fibers with a length of about 6 mm or 9 mm are selected, and the fiber addition amount is 0.4%-1.2% of the proppant mass; the proppant types are 100-200 mesh microproppant, 70-140 mesh silt sand, and 40-70 mesh or 30-50 mesh proppant, among which the mass ratio of 100-200 mesh and 70-140 mesh to 40-70 mesh or 30-50 mesh proppant is 7:3 to 1:0, and a small amount of 100-200 mesh microproppant is taken according to the proportion of secondary and above fractures, and the amount is reduced as the complexity of the fractures decreases.
[0050] For the three types of reservoirs, fibers with a length of about 3mm-6mm are selected, and the fiber addition amount is 0.4%-0.8% of the proppant mass; the proppant types are 100-200 mesh micro proppant, 70-140 mesh silt sand, and 40-70 mesh or 30-50 mesh proppant, among which the mass ratio of 100-200 mesh and 70-140 mesh to 40-70 mesh or 30-50 mesh proppant is 7:3 to 1:0. Among them, the proportional relationship between 100-200 mesh and 70-140 mesh increases with the complexity of the fracture, and the number of 100-200 mesh particles increases.
[0051] After the selection of fracturing materials is determined, the fracturing fluid and proppant are configured. The configuration of fracturing fluid is to first stir the drag reducer and water (or flowback fluid) in the liquid tank to form slippery water, and then add the stabilizer and stir evenly; the configuration of proppant is to add the fiber into the sand tank and stir evenly with the proppant. During the construction process, the two are extracted from the liquid tank and the sand tank respectively according to a certain concentration, and they are mixed during the flow of the pipeline.
[0052] Finally, the fracturing construction pumping process is carried out. For Class I reservoirs, 70-140 mesh silt sand is mixed with 6mm fiber and pumped into the formation at the initial and intermediate stages of fracturing, and in the later stage of construction, 40-70 mesh (or 30-50 mesh) proppant and 6mm or 9mm fiber are mixed and injected into the formation. For Class II reservoirs, 100-200 mesh micro proppant and 70-140 silt sand are mixed, 6mm fiber is added, and pumped into the formation at the initial and intermediate stages of fracturing; in the later stage of fracturing construction, 40-70 mesh (or 30-50 mesh) proppant and 6mm or 9mm fiber are mixed and pumped into the formation. For the three types of reservoirs, in the initial and intermediate pumping stages of fracturing, 100-200 mesh microproppant and 70-140 silt sand are mixed, 3mm fiber is added, and pumped into the formation; in the later stage of fracturing construction, 40-70 mesh (or 30-50 mesh) proppant and 6mm fiber are mixed and pumped into the formation.
[0053] Example 1
[0054] In a specific embodiment, the construction of the 8th section of a horizontal well in the tight gas reservoir of Shaximiao Formation in western Sichuan is taken as an example. The horizontal well has 11 sections of heterogeneous perforation, and the in-situ stress, mechanics, physical properties and construction parameters of the 8th section are shown in Table 1.
[0055] Table 1 Geomechanics and construction parameters of the 8th section of a well
[0056]
[0057]
[0058] The established crack propagation model is used to simulate the crack propagation morphology in this section, and the following is obtained: Figure 2 The fracture morphology is shown. It can be seen that due to the strong homogeneity of the reservoir and the lack of natural fractures, the fractures generated are mainly main fractures, and no obvious branch fractures are generated. It can also be seen that due to the competitive expansion of multiple clusters of fractures, the fractures on both sides of this section are longer, about 175m, and the middle fracture is shorter, only more than 100m. The statistics of eight fractures show that the average width of the main fracture is 6mm and the average fracture height is 30m.
[0059] According to the fracture morphology of the example well, a proppant placement experiment was carried out in a laboratory flat plate fracture to compare the proppant placement morphology in the fracture obtained by conventional slick water sand carrying and the proppant placement morphology obtained by the fiber-assisted sand carrying global proppant placement method proposed in this article, thereby verifying the method proposed in the present invention.
[0060] First, the on-site fracturing construction conditions are converted into experimental conditions in the laboratory according to the similarity principle. Here, the similarity criterion that the Reynolds number of the on-site fracture flow is the same as the Reynolds number in the fracture of the experimental device is adopted, that is,
[0061] Re F =Re E
[0062] In the above formula, Re F and Re E are the Reynolds numbers for flow in field and laboratory fractures, respectively.
[0063] Taking the slit width W as the characteristic dimension, we have
[0064]
[0065] In the above formula, Q F —On-site displacement, take 18m according to the table above 3 / min; W E —The width of the crack on the plate of the experimental device is the same as the average width of the crack on site, which is 6 mm; H E —The height of the crack on the experimental device plate, 0.3m; H F —Average height of artificial cracks obtained by simulation, 30m; W F —Average width of artificial cracks, 6mm.
[0066] According to the above calculation formula, the pump displacement Q required for the experiment can be calculated: E It is 11.25L / min. In the actual experiment, the pump displacement is 10L / min.
[0067] It can be seen that the natural fractures in this well are not well developed and the reservoir heterogeneity is weak. Figure 2 The fracture morphology simulation results given show that this section has a fracture structure dominated by main fractures, so it is classified as a type of reservoir in the present invention.
[0068] During the indoor proppant delivery and placement experiment, the amount of drag reducer added was 0.3% of the liquid volume, and the amount of stabilizer added was 0.2% of the liquid volume; the fiber with a length of 6 mm was selected, and the fiber addition amount was 0.4% of the proppant mass; the proppant type was 70-140 mesh silt sand, and the ratio of proppant mass to fracturing fluid volume during the pumping process was 160 kg / m 3 The experiment was carried out in a flat plate fracture experimental device with a length*height*width of 4m*0.3m*6mm. The configuration and pumping process of the fracturing fluid and proppant were carried out according to the specific measures of step (4) in the technical solution of the invention.
[0069] Figure 3The proppant paving morphology in the flat plate crack of the experimental device at two different time points using the method of the present invention is given. It can be seen that under the conditions of the proppant paving method proposed by the present invention, the proppant can first move to a relatively long distance after entering the crack, and accumulate and pave in the crack in a relatively fluffy state; when the injection time is 5 minutes and 30 seconds, the entire flat plate crack is basically completely filled with proppant in both length and height directions, achieving full-area support for the entire crack.
[0070] Figure 4 The comparative experimental results of proppant placement in fractures under conventional slickwater sand-carrying conditions are given (the pumping rate, proppant size and concentration, drag-reducing agent dosage and other conditions are the same). Figure 4 As can be seen from the figure, due to the formation of a relatively dense and compact accumulation of proppant, when the injection time is 3 minutes and 9 seconds, only a thin layer of proppant accumulation is formed at the bottom of the fracture, while when the injection time is 7 minutes and 30 seconds, the proppant paving area in the fracture is less than a quarter of the fracture volume, which is consistent with the Figure 3 There are obvious differences.
[0071] Analysis of the production Figure 3 and Figure 4 The reason for the difference in proppant accumulation morphology is that when the global support laying technology proposed in the present invention is used, the fiber-stabilizer-slippery water-proppant four form a stable mass structure during the pumping process ( Figure 5 As shown in the figure, there is a large porosity between the proppants inside the cluster structure, and the average density of the entire cluster structure is small, which reduces the sedimentation rate of the proppant during transportation. At the same time, there is a large porosity between the cluster structures during the stacking process. Combining the above two reasons, the same amount of proppant can greatly improve the laying degree in the length and height directions, and the full-area laying of proppant in the entire fracture is achieved. It can be seen that the method proposed by the present invention can improve the laying effect of proppant and fiber.
[0072] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions and improvements made within the spirit and principles of the present invention should be included in the protection scope of the present invention.
Claims
1. A method for achieving full-area support of proppant in unconventional reservoir fracturing fractures, characterized in that: The following steps are involved: 1) For the unconventional reservoir to be transformed, basic parameters are collected and a reservoir geological model is established based on the basic parameters; 2) Simulate fracture propagation based on fracturing design parameters to obtain fracture morphology produced by fracturing in unconventional reservoirs; 3) Classifying the cracks into main cracks, primary cracks, and secondary cracks and above according to the crack morphology, and calculating the volume ratio of each type of cracks; 4) Unconventional reservoirs are divided into Class I, Class II, and Class III according to the volume ratio of each type of fracture, and the parameters of the drag reducing agent, fiber, and proppant are designed to carry out fracturing construction.
2. The method for global propping of unconventional reservoir fracturing proppant as claimed in claim 1, wherein fracture propagation simulation is performed using fracture propagation numerical simulation software based on phase field method.
3. The method for full-area support of unconventional reservoir fracturing proppant according to claim 1, wherein the first-level secondary fractures are secondary fractures other than the main fractures and have a fracture width greater than 1 mm, and the second-level and above secondary fractures are secondary fractures with a fracture width of less than 1 mm.
4. The method for full-area support of unconventional reservoir fracturing proppant according to claim 1, wherein the first category is a reservoir in which the main fracture volume after transformation accounts for more than 95% of the total fracture volume, the second category is a reservoir in which the main fracture volume after transformation accounts for more than 75% and less than 95%, and the third category is a reservoir in which the main fracture volume after transformation is less than 70%.
5. The method for full-area support of unconventional reservoir fracturing proppant as claimed in claim 1, for Class I reservoirs, the concentration of the drag reducing agent is 0.3%-0.6% of the liquid volume, and the concentration of the fiber stabilizer is 0.2%-0.4% of the liquid volume; for Class II reservoirs, the concentration of the drag reducing agent is 0.2%-0.5% of the liquid volume, and the concentration of the fiber stabilizer is 0.2%-0.5% of the liquid volume; for Class III reservoirs, the concentration of the drag reducing agent is 0.1%-0.3% of the liquid volume, and the concentration of the fiber stabilizer is 0.2%-0.6% of the liquid volume.
6. The method for global proppant support of unconventional reservoir fracturing cracks as claimed in claim 1, for a type of reservoir, a fiber with a length of 6 mm to 9 mm is selected, the fiber addition amount is 0.4% to 1.2% of the proppant mass, and the proppant type is 70-140 mesh silt sand and 40-70 mesh or 30-50 mesh proppant; For the second type of reservoir, the fiber length is 6 mm or 9 mm, the fiber addition amount is 0.4%-1.2% of the proppant mass, and the proppant types are 100-200 mesh micro proppant, 70-140 mesh silt sand, and 40-70 mesh or 30-50 mesh proppant; For the three types of reservoirs, fibers with a length of 3 mm to 6 mm were selected, the fiber addition amount was 0.4% to 0.8% of the proppant mass, and the proppant types were 100-200 mesh microproppant, 70-140 mesh silt sand, and 40-70 mesh or 30-50 mesh proppant.
7. The method for full-area propping of unconventional reservoir fracturing cracks according to claim 1, wherein the mass ratio of 70-140 mesh to 40-70 mesh or 30-50 mesh proppant in a reservoir is 7:3 to 1:0; For the second type of reservoir, the mass ratio of 100-200 mesh and 70-140 mesh to 40-70 mesh or 30-50 mesh proppant is 7:3 to 1:0; For the three types of reservoirs, the mass ratio of 100-200 mesh and 70-140 mesh to 40-70 mesh or 30-50 mesh proppant is 7:3 to 1:
0.
8. The method for global propping of unconventional reservoir fracturing proppant as claimed in claim 7, wherein the ratio between 100-200 mesh and 70-140 mesh increases with the complexity of the fracture, and the number of 100-200 mesh particles increases.
9. The method for global propping of unconventional reservoir fracturing cracks as claimed in claim 1, wherein for a type of reservoir, 70-140 mesh silt mixed with 6 mm fiber is pumped into the formation in the initial and intermediate stages of fracturing, and in the later stages of construction, 40-70 mesh or 30-50 mesh proppant and 6 mm or 9 mm fiber are mixed and injected into the formation; For Class II reservoirs, at the initial and intermediate stages of fracturing, 100-200 mesh microproppant and 70-140 silt sand are mixed, 6 mm fiber is added, and pumped into the formation. At the later stage of fracturing construction, 40-70 mesh or 30-50 mesh proppant and 6 mm or 9 mm fiber are mixed and pumped into the formation. For the three types of reservoirs, in the initial and intermediate pumping stages of fracturing, 100-200 mesh microproppant and 70-140 silt sand are mixed, 3mm fiber is added, and pumped into the formation. In the later stage of fracturing construction, 40-70 mesh or 30-50 mesh proppant and 6mm fiber are mixed and pumped into the formation.
10. A device for achieving full-area support of proppant in unconventional reservoir fracturing fractures, characterized in that: include: at least one processor and a memory in communication with the processor; The memory stores instructions executable by the processor, and the instructions are executed by at least one processor so that the at least one processor can execute the computing method described in any one of claims 1 to 9.