Tight gas fiber sand fracturing optimization design method and system

Abstract

The invention discloses a tight gas fiber sand fracturing optimization design method and system, and the method comprises the steps: employing a numerical simulation technology, taking the reservoir transformation volume and the crack complexity as optimization targets, and carrying out the optimization to obtain fracturing construction parameters; under the optimized fracturing construction parameters, indoor experiments are carried out, and the fiber type, the use amount, the pump injection mode and the like which have the minimum influence on the backflow capacity of a proppant filling layer and have the optimal sand prevention effect are determined, so that the whole process of tight gas fiber sand fracturing is optimized, the sand production rate is effectively reduced, the backflow capacity of a crack is guaranteed, and the fracturing efficiency is improved. And the reservoir transformation effect is improved to the maximum extent, the yield is increased, and the cost is reduced.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas development, and in particular relates to a method and system for optimizing the design of dense gas fiber and sand fracturing. Background Art

[0002] Fracturing proppants are spherical particles used to support artificial fractures to improve the oil and gas seepage capacity of the formation. They are one of the key materials in the volume fracturing operation of tight sandstone. The types of proppants can be divided into quartz sand (mineral sand and natural river sand), ceramsite, and resin-coated proppants according to the different materials. At present, the main proppants used in tight sandstone fracturing are 70 / 140 mesh quartz sand, 40 / 70 mesh quartz sand, 40 / 70 mesh coated quartz sand, and 30 / 50 mesh ceramsite. As of July 2021, a total of 27 tight sandstone horizontal wells in a certain basin were fracturable. During the drainage period, many wells had varying degrees of sand production. Among them, the horizontal wells in the ⅹⅹ-ⅹⅹ block had the most serious sand production, up to 170t, and a sand production rate of 6.93%. After tailing the coated quartz sand, the degree of sand production improved, but the effects were different. The sand production and sand production rate of some wells were still high.

[0003] It can be seen from this that the existing sand-adding fracturing technology has a high sand discharge rate after fracturing, which makes it difficult to stably control the backflow capacity of the fractures, thereby affecting production and even damaging surface pipelines, increasing surface maintenance costs. Summary of the invention

[0004] In order to solve the problems of the existing sand-adding fracturing technology, such as high sand production rate after fracturing, affecting the backflow capacity of fractures, resulting in poor production, and even damaging ground pipelines, increasing ground maintenance costs, etc., the present invention provides a dense gas fiber sand-adding fracturing optimization design method and system. The present invention uses numerical simulation technology, takes reservoir transformation volume and fracture complexity as optimization targets, and optimizes fracturing construction parameters; and conducts indoor experiments under the optimized fracturing construction parameters to determine the fiber type, dosage and pumping method that have the least impact on the backflow capacity of the proppant filling layer and the best sand prevention effect, thereby achieving optimization of the entire dense gas fiber sand-adding fracturing process, effectively reducing the sand production rate, ensuring the backflow capacity of fractures, maximizing the transformation effect of the reservoir, increasing production, and reducing costs.

[0005] The present invention is achieved through the following technical solutions:

[0006] A dense gas fiber plus sand fracturing optimization design method, the method comprising:

[0007] Determine the reservoir section based on the logging curve, identify the reservoir thickness, and divide the oil testing section;

[0008] Combined with the rock mechanics parameter curve of the reservoir section in the logging curve, the stress and fracture pressure profile are calculated, and the cluster perforation position is optimized according to the physical properties of the reservoir section and the fracture pressure profile;

[0009] According to the basic geological parameters, the proppant type is selected, and the reservoir transformation volume and fracture complexity are obtained by numerical simulation technology to optimize the fracturing construction parameters;

[0010] Under optimized fracturing operation parameters, indoor experiments were conducted to optimize fiber type and fiber dosage with the goal of minimizing the impact on the conductivity of the proppant packing layer and maximizing the sand control effect;

[0011] Under the optimized fiber type and fiber dosage, the fiber pumping method is optimized with the goal of maximizing gas production while ensuring the minimum sacrifice of permeability, the least sand production in the fractures, and the optimal conductivity of the entire fracture.

[0012] The existing sand-adding fracturing technology has a high sand discharge rate after fracturing, and the fracture backflow capacity cannot be stably controlled, which ultimately leads to a series of problems such as poor tight gas production and even damage to ground pipelines, increased ground maintenance costs, etc. The optimization design method proposed in the present invention optimizes the tight gas fiber sand-adding fracturing construction parameters using numerical simulation technology, and conducts indoor experiments under the optimized fracturing construction parameters to optimize the fiber type, fiber dosage and fiber pumping process, thereby optimizing the entire process of unconventional oil and gas sand control and sand prevention fracturing, effectively reducing the sand production rate, ensuring the fracture backflow capacity, improving the transformation effect of the reservoir, increasing oil and gas production, and reducing costs.

[0013] As a preferred embodiment, the method of the present invention selects a well section with a shale content of less than 20% and a porosity of more than 7% as the oil testing section.

[0014] As a preferred embodiment, the method for calculating the rupture pressure profile of the present invention is specifically as follows:

[0015] Calibrate rock mechanics parameters through data from rock mechanics laboratory experiments;

[0016] The fracture pressure curve of the reservoir section is calculated using the calibrated rock mechanics parameters.

[0017] As a preferred embodiment, the present invention optimizes the perforation position based on the fracture pressure value not exceeding 5 MPa.

[0018] As a preferred embodiment, the fracturing construction parameter optimization process of the present invention specifically includes:

[0019] Select the proppant type according to the effective closure stress of the well logging, where the proppant type selection criteria are: effective closure stress below 42MPa belongs to the quartz sand support range, effective closure stress below 48MPa belongs to the coated quartz sand support range, and effective closure stress below 70MPa belongs to the ceramsite support range; if at least two proppant combinations are selected, the ratio is determined according to the reservoir geological characteristics and the Young's modulus;

[0020] Using numerical simulation technology, the reservoir transformation volume and fracture complexity index under different fracturing construction parameters are calculated;

[0021] The optimal fracturing construction parameters are determined based on the maximum weighted value of the reservoir transformation volume and the fracture complexity index.

[0022] As a preferred embodiment, the calculation method of the reservoir transformation volume of the present invention is:

[0023] V=L*H*W, where V represents the reservoir transformation volume, m 3 , L represents the length of the crack, m, H represents the height of the crack, m, and W represents the width of the crack, m;

[0024] The calculation method of the crack complexity index is:

[0025] As a preferred embodiment, the fiber type and fiber dosage optimization process of the present invention specifically includes:

[0026] Under the optimized fracturing construction parameters, conduct indoor conductivity experiments and optimize fiber types;

[0027] Under the optimized fracturing construction parameters, indoor experiments on sand prevention and control were carried out to optimize the fiber dosage.

[0028] As a preferred embodiment, the fiber pumping mode optimization process of the present invention is specifically as follows:

[0029] The tail-chasing fiber injection method is adopted, and the fiber is injected according to the optimized fiber type and fiber dosage at each stage before and after the temporary plugging material is placed.

[0030] On the other hand, the present invention also proposes a dense gas fiber plus sand fracturing optimization design system, the system comprising:

[0031] A reservoir analysis unit, which determines the reservoir section, identifies the reservoir thickness, and divides the oil testing section according to the well logging curve;

[0032] A perforation position optimization unit, wherein the perforation position optimization unit calculates stress and fracture pressure profiles in combination with the rock mechanics parameter curve of the reservoir section in the well logging curve, and optimizes cluster perforation positions according to the physical properties of the reservoir section and the fracture pressure profile;

[0033] A construction parameter optimization unit, wherein the construction parameter optimization unit selects the proppant type according to the geological basic parameters, obtains the reservoir transformation volume and the complexity of the fractures by using numerical simulation technology, and optimizes the fracturing construction parameters;

[0034] And, a fiber process parameter optimization unit, which conducts indoor experiments under optimized fracturing construction parameters to optimize the fiber type and fiber dosage with the goal of minimizing the impact on the conductivity of the proppant filling layer and optimizing the sand control effect; and optimizes the fiber pumping method with the goal of maximizing gas production under the optimized fiber type and fiber dosage, while ensuring the minimum sacrifice of permeability, the least sand production in the fractures, and the optimal conductivity of the entire fracture.

[0035] As a preferred embodiment, the system of the present invention further includes:

[0036] An output unit is used to output the optimal solution.

[0037] Compared with the prior art, the present invention has the following advantages and beneficial effects:

[0038] The present invention optimizes the construction parameters of dense gas fiber and sand fracturing by using numerical simulation technology, and conducts indoor experiments under the optimized fracturing construction parameters to optimize the fiber type, fiber dosage and fiber pumping process, thereby realizing the optimization of the whole process of unconventional oil and gas sand control and sand prevention fracturing, overcoming a series of problems of the existing conventional sand fracturing technology, such as high sand discharge rate after fracturing, inability to stably control the backflow capacity of fractures, and ultimately poor production, and even puncturing of ground pipelines, and increased ground maintenance costs.

[0039] The present invention optimizes the sand prevention and control of tight sandstone reservoirs after compression, effectively reduces the sand production rate, ensures the conductivity of fractures, maximizes the transformation effect of the reservoir, reduces maintenance costs, and provides technical support for the formulation of fiber sand addition optimization plans for tight gas horizontal wells. BRIEF DESCRIPTION OF THE DRAWINGS

[0040] The drawings described herein are used to provide a further understanding of the embodiments of the present invention, constitute a part of this application, and do not constitute a limitation of the embodiments of the present invention. In the drawings:

[0041] Figure 1 The figure is a flow chart of a method according to an embodiment of the present invention.

[0042] Figure 2 This is the optimized design diagram for reservoir segmentation and clustering of Well ZQ206-6-H2.

[0043] Figure 3 is the reservoir transformation volume under different cluster spacing.

[0044] Figure 4 is the crack complexity index under different cluster spacing.

[0045] Figure 5 The relationship between the sand output and the liquid discharge rate of 40 / 70 mesh with different concentrations of 3mm fiber (30MPa closing pressure).

[0046] Figure 6 The relationship between the sand output and the liquid discharge rate of 70 / 140 mesh for 9mm fiber of different concentrations (30MPa closing pressure).

[0047] Figure 7 The five-year cumulative gas production simulated under three injection methods.

[0048] Figure 8 4 is a system principle block diagram of an embodiment of the present invention. DETAILED DESCRIPTION

[0049] In order to make the objectives, technical solutions and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with embodiments and drawings. The exemplary embodiments of the present invention and their description are only used to explain the present invention and are not intended to limit the present invention.

[0050] Embodiment 1:

[0051] The existing sand-adding fracturing technology has a high sand discharge rate after fracturing, and the fracture conductivity cannot be stably controlled, which ultimately leads to a series of problems such as poor tight gas production, even puncturing ground pipelines, and increasing ground maintenance costs. Based on this, this embodiment proposes a tight gas fiber sand-adding fracturing optimization design method. The optimization design method proposed in this embodiment uses numerical simulation technology to optimize the reservoir transformation volume and fracture complexity as optimization targets to obtain the optimal fracturing construction parameters; under the optimal fracturing construction parameters, indoor experiments are carried out to study the effects of different fiber types, different fiber concentrations, and fiber dosage on the conductivity and sand production of the proppant filling layer, so as to obtain the fiber sand-adding fracturing parameters with the least impact on the conductivity of the proppant filling layer and the best sand control effect, so as to achieve the optimization design of the entire process of fiber sand-adding fracturing, effectively reduce the sand production rate, ensure the fracture conductivity, maximize the transformation effect of the reservoir, increase the tight gas production, and reduce maintenance costs.

[0052] Specific as Figure 1 As shown, the optimization design method proposed in this embodiment includes the following steps:

[0053] Step 1: Determine the reservoir section based on the logging curve, identify the reservoir thickness, and divide the oil testing section.

[0054] Step 2, combining the rock mechanics parameter curve of the reservoir section in the well logging curve, calculating the stress and fracture pressure profile, and optimizing the cluster perforation position according to the physical properties of the reservoir section and the fracture pressure profile;

[0055] Step 3: Select the proppant type according to the basic geological parameters, and use numerical simulation technology to obtain the reservoir transformation volume and fracture complexity, and optimize the fracturing construction parameters;

[0056] Step 4: Conducting indoor experiments under optimized fracturing construction parameters to optimize the fiber type and fiber dosage with the goal of minimizing the impact on the conductivity of the proppant packing layer and maximizing the sand control effect;

[0057] Step 5: Under the optimized fiber type and fiber dosage, the fiber pumping method is optimized with the goal of maximizing gas production while ensuring the minimum sacrifice of permeability, the minimum sand production in the fractures, and the optimal conductivity of the entire fracture.

[0058] In an optional implementation manner, this embodiment selects a certain block of tight sandstone reservoir for exemplary analysis, and the obtained logging curves include but are not limited to: gamma curve, shale content, rock density, porosity, permeability, water saturation, triaxial stress, rock elastic modulus and Poisson's ratio, etc. Figure 2 As shown. The reservoir section is determined based on the signal characteristics of the logging curve, and further, based on the logging curve, the layer section with better physical properties (porosity, permeability), better gas content (high total hydrocarbon content, low resistivity), and lower mud content is identified from the reservoir section as the oil testing section, that is, the fracturing construction section. Specifically, in this embodiment, the well section with lower mud content (usually less than 20%) and higher porosity (more than 7%) is selected as the oil testing section of this well.

[0059] In an optional implementation, the rock mechanics parameters such as the elastic modulus, Poisson's ratio, and the magnitude and direction of the three-dimensional stress (i.e., the maximum horizontal principal stress, the minimum horizontal principal stress, and the vertical stress) of the reservoir rock in the logging curve are obtained by calculation from basic parameters, including but not limited to the acoustic time difference, the longitudinal and transverse wave velocity ratio, etc., and need to be calibrated with the data of the rock mechanics indoor experiment. The fracture pressure curve of the reservoir section is calculated by the calibrated rock mechanics parameters, and the perforation position is selected according to the fracture pressure curve. Specifically, the perforation position can be optimized based on the fracture pressure value not exceeding 5MPa.

[0060] In an optional implementation manner, the fracturing construction parameters include but are not limited to cluster spacing, sand addition amount, liquid amount, pump injection displacement, etc. Step 3 also includes the following sub-steps:

[0061] Step 31, select the proppant type. Specifically, the effective closure stress below 42MPa belongs to the quartz sand support range; the effective closure stress below 48MPa belongs to the coated quartz sand support range; the effective closure stress below 70MPa belongs to the ceramsite support range; this embodiment takes the ZQ206-6-H2 well as an example for illustrative explanation. The effective closure stress of the ZQ206-6-H2 well is 40MPa, which meets the support requirements of quartz sand and coated quartz sand. Therefore, the support type can be selected as 70 / 140 mesh quartz sand + 40 / 70 mesh coated quartz sand combined particle size, and the preferred ratio is 8:2. In other optional implementations, the ratio can be determined according to the reservoir geological characteristics and the size of the Young's modulus, so as to facilitate smooth sand addition construction.

[0062] Step 32, calculate the reservoir transformation volume and the fracture complexity. Specifically, the calculation method of the reservoir transformation volume is: V = L*H*W, where V represents the reservoir transformation volume, m 3 , L represents the length of the crack, m, H represents the height of the crack, m, and W represents the width of the crack, m; the calculation method of the crack complexity index is:

[0063] Step 33, using petrel simulation technology, to study the reservoir transformation volume and fracture complexity index under different fracturing construction parameters, so as to determine the optimal fracturing construction parameters. This embodiment takes the optimization of cluster spacing as an example to study the reservoir transformation volume and fracture complexity index under different cluster spacing designs of the ZQ206-6-H2 well, such as Figure 3-4 As shown in the figure, the optimal cluster spacing is determined based on the maximum weighted value of the reservoir transformation volume and the fracture complexity index.

[0064] In an optional implementation manner, step 4 further includes the following sub-steps:

[0065] Step 41, under the optimized fracturing construction parameters, conduct indoor experiments on conductivity to optimize the fiber type. Specifically, based on the proppant type selected in the above step, which is a combined particle size of 70 / 140 mesh quartz sand + 40 / 70 mesh coated quartz sand, conduct indoor experiments on the conductivity of 70 / 140 mesh quartz sand and 40 / 70 mesh coated quartz sand at different closing pressures, fiber lengths, and fiber concentrations, and obtain the conductivity of different types of proppants at different fiber lengths and fiber concentrations as shown in Table 1. It can be seen from Table 1 that the 9mm fiber has the least damage to the conductivity of the 70 / 140 mesh quartz sand; the 3mm fiber has the least damage to the conductivity of the 40 / 70 mesh coated quartz sand, so 40 / 70+3mm and 70 / 140+9mm are preferred.

[0066] Table 1 Conductivity of different types of proppants at different fiber lengths and fiber concentrations

[0067]

[0068] Step 42, under the optimized fracturing construction parameters, conduct sand control indoor experiments to optimize the fiber dosage. Specifically, a conventional diversion chamber is used to conduct sand control indoor experiments under different fiber concentrations. The results show that 40 / 70+3mm uses a fiber concentration of 0.6% with a lower sand output and better sand control effect, and 70 / 140+9mm uses a fiber concentration of 0.4% with a lower sand output and better sand control effect. Therefore, 40 / 70+3mm (0.6%) and 70 / 140+9mm (0.4%) can be preferred. Figure 5-Figure 6 shown.

[0069] In an optional implementation manner, step 5 further includes:

[0070] The tail chase injection method (method 1), the plug injection method (method 2), and the full-process accompanying injection method (method 3) were respectively adopted. In each stage before and after the temporary plugging material was placed, the fiber was injected (injected into the wellbore together with the proppant) in the manner of 40 / 70+3mm (0.6%) and 70 / 140+9mm (0.4%), and the gas production was increased while ensuring the minimum sacrifice of permeability, the minimum sand production in the fracture, and the optimal conductivity of the whole fracture. The second stage pumping program table of the ZQ206-6-H2 well was obtained as shown in Table 2.

[0071] Table 2 The second stage of pumping program of ZQ206-6-H2 well

[0072]

[0073]

[0074] The numerical simulation technology can be used to obtain the five-year cumulative gas production of the three injection methods, such as Figure 7 As shown in the figure, it can be seen that among the three methods, the cumulative gas production of method 2 is the highest, so method 2, that is, the slug type, is preferred as the optimal fiber pumping method.

[0075] This embodiment targets the characteristics of a certain tight gas sandstone reservoir, studies the effects of different cluster spacing, sand addition intensity, liquid usage scale, displacement, etc. in sandstone formations on fracture extension, deepens the influence of construction parameters on reservoir transformation volume and fracture complexity, and determines the optimal construction parameters with reservoir transformation volume and fracture complexity as the target. At the same time, through indoor experiments, the effects of different fiber types, dosages, and pumping methods on fracture conductivity and oil and gas production are studied, and the optimal fiber type, fiber dosage, and fiber pumping method with minimal damage to conductivity and optimal sand control effect are obtained, thereby achieving optimization of the entire process of unconventional oil and gas sand control and fracturing, effectively reducing sand production rate, ensuring fracture backflow capacity, improving reservoir transformation effect, increasing oil and gas production, and reducing costs, providing technical support for the formulation of fiber sand addition optimization plans for tight gas horizontal wells.

[0076] Based on the same technical concept as above, this embodiment also proposes a dense gas fiber plus sand fracturing optimization design system, specifically as follows Figure 8 As shown, the fracturing optimization design system of this embodiment includes:

[0077] The reservoir analysis unit determines the reservoir section according to the logging curve, identifies the reservoir thickness, and divides the oil testing section.

[0078] The perforation position optimization unit calculates the stress and fracture pressure profiles based on the rock mechanics parameter curve of the reservoir section in the well logging curve, and optimizes the clustered perforation positions according to the physical properties of the reservoir section and the fracture pressure profile.

[0079] The construction parameter optimization unit selects the proppant type according to the basic geological parameters, and uses numerical simulation technology to obtain the reservoir transformation volume and crack complexity, and optimizes the fracturing construction parameters.

[0080] The fiber process parameter optimization unit conducts indoor experiments under optimized fracturing construction parameters, optimizing the fiber type and fiber dosage with the goal of minimizing the impact on the conductivity of the proppant filling layer and optimizing the sand control effect; and optimizes the fiber pumping method with the goal of minimizing sand production in the fractures and optimizing the conductivity of the entire fracture under the optimized fiber type and fiber dosage, while ensuring the minimum sacrifice of permeability.

[0081] The output unit is used to output the optimal solution, including the optimal fracturing construction parameters and fiber process parameters.

[0082] The specific implementation methods described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific implementation method of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A dense gas fiber plus sand fracturing optimization design method, characterized in that: The method comprises: Determine the reservoir section based on the logging curve, identify the reservoir thickness, and divide the oil testing section; Combined with the rock mechanics parameter curve of the reservoir section in the logging curve, the stress and fracture pressure profile are calculated, and the cluster perforation position is optimized according to the physical properties of the reservoir section and the fracture pressure profile; According to the basic geological parameters, the proppant type is selected, and the reservoir transformation volume and fracture complexity are obtained by numerical simulation technology to optimize the fracturing construction parameters; Under optimized fracturing operation parameters, indoor experiments were conducted to optimize fiber type and fiber dosage with the goal of minimizing the impact on the conductivity of the proppant packing layer and maximizing the sand control effect; Under the optimized fiber type and fiber dosage, the fiber pumping method is optimized with the goal of maximizing gas production while ensuring the minimum sacrifice of permeability, the least sand production in the fractures, and the optimal conductivity of the entire fracture.

2. A dense gas fiber plus sand fracturing optimization design method according to claim 1, characterized in that: The method selects a well section with a shale content lower than 20% and a porosity higher than 7% as a well testing section.

3. The method for optimizing the design of dense gas fiber plus sand fracturing according to claim 1, characterized in that: The method for calculating the rupture pressure profile is specifically as follows: Calibrate rock mechanics parameters through data from rock mechanics laboratory experiments; The fracture pressure curve of the reservoir section is calculated using the calibrated rock mechanics parameters.

4. A dense gas fiber plus sand fracturing optimization design method according to claim 3, characterized in that: The perforation position is optimized based on the fracture pressure value not exceeding 5 MPa.

5. The method for optimizing the design of dense gas fiber plus sand fracturing according to claim 1, characterized in that: The fracturing construction parameter optimization process specifically includes: Select the proppant type according to the effective closure stress of the well logging, where the proppant type selection criteria are: effective closure stress below 42MPa belongs to the quartz sand support range, effective closure stress below 48MPa belongs to the coated quartz sand support range, and effective closure stress below 70MPa belongs to the ceramsite support range; if at least two proppant combinations are selected, the ratio is determined according to the reservoir geological characteristics and the Young's modulus; Using numerical simulation technology, the reservoir transformation volume and fracture complexity index under different fracturing construction parameters are calculated; The optimal fracturing construction parameters are determined based on the maximum weighted value of the reservoir transformation volume and the fracture complexity index.

6. A dense gas fiber plus sand fracturing optimization design method according to claim 5, characterized in that: The calculation method of the reservoir transformation volume is: V=L*H*W, where V represents the reservoir transformation volume, m 3 , L represents the length of the crack, m, H represents the height of the crack, m, and W represents the width of the crack, m; The calculation method of the crack complexity index is:

7. The method for optimizing the design of dense gas fiber plus sand fracturing according to claim 1, characterized in that: The fiber type and fiber dosage optimization process specifically includes: Under the optimized fracturing construction parameters, conduct indoor conductivity experiments and optimize fiber types; Under the optimized fracturing construction parameters, indoor experiments on sand prevention and control were carried out to optimize the fiber dosage.

8. The method for optimizing the design of dense gas fiber plus sand fracturing according to claim 1, characterized in that: The fiber pumping mode optimization process is specifically as follows: The tail-chasing fiber injection method is adopted, and the fiber is injected according to the optimized fiber type and fiber dosage at each stage before and after the temporary plugging material is placed.

9. A dense gas fiber plus sand fracturing optimization design system, characterized in that: The system comprises: A reservoir analysis unit, which determines the reservoir section, identifies the reservoir thickness, and divides the oil testing section according to the well logging curve; A perforation position optimization unit, wherein the perforation position optimization unit calculates stress and fracture pressure profiles in combination with the rock mechanics parameter curve of the reservoir section in the well logging curve, and optimizes cluster perforation positions according to the physical properties of the reservoir section and the fracture pressure profile; A construction parameter optimization unit, wherein the construction parameter optimization unit selects the proppant type according to the geological basic parameters, obtains the reservoir transformation volume and the complexity of the fractures by using numerical simulation technology, and optimizes the fracturing construction parameters; And, a fiber process parameter optimization unit, which conducts indoor experiments under optimized fracturing construction parameters to optimize the fiber type and fiber dosage with the goal of minimizing the impact on the conductivity of the proppant filling layer and optimizing the sand control effect; and optimizes the fiber pumping method with the goal of maximizing gas production under the optimized fiber type and fiber dosage, while ensuring the minimum sacrifice of permeability, the least sand production in the fractures, and the optimal conductivity of the entire fracture.

10. A dense gas fiber plus sand fracturing optimization design system according to claim 9, characterized in that: The system further comprises: An output unit is used to output the optimal solution.

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