Shale gas reservoir production degree characterization method, device and equipment

Abstract

The invention discloses a shale gas reservoir exploitation degree characterization method, device and equipment, and the method comprises the steps: determining a first influence factor of the shale gas reservoir exploitation degree based on the influence of the desorption effect and slippage effect of a reservoir matrix on the shale gas reservoir exploitation volume; determining a second influence factor on the shale gas reservoir production degree on the basis of the influence of the fracture form parameters of the reservoir and the transformation area parameters on the shale gas reservoir production speed; and on the basis of the first influence factor and the second influence factor, predicting the productivity of the shale gas reservoir established on the basis of the wavefront rapid propulsion method so as to represent the utilization degree of the shale gas reservoir. By means of the method, pressure prediction and yield analysis in the reservoir exploitation range are achieved, and then gas reservoir parameters of shale gas exploitation are optimized and improved.

Description

Technical Field

[0001] The present invention relates to the technical field of shale gas reservoir production, and in particular to a method, device and equipment for characterizing the degree of production of shale gas reservoirs. Background Art

[0002] Shale gas refers to natural gas that is rich in organic matter, mature dark mud shale or high-carbon mud shale. It is due to the adsorption of organic matter or the existence of cracks and matrix pores in the rock, which enables the storage and preservation of certain commercially valuable natural gas of biological origin, pyrolysis origin, and a mixture of the two.

[0003] The gas content of shale is an important parameter for calculating the potential of shale gas resources and predicting reserves, and is of great significance to shale gas exploration and development. The gas content of shale refers to the volume of natural gas contained in each ton of shale under standard conditions (0°C, 101.325kPa), including free gas, adsorbed gas and dissolved gas.

[0004] Shale gas has multiple coupling modes such as adsorption and desorption, diffusion flow and seepage. The determination of shale gas content currently lacks a specific industry standard and mainly refers to the technical methods of the coalbed methane industry. The methods for determining gas content can be roughly divided into two categories: direct method and indirect method. The direct method is the desorption method, which refers to obtaining the actual gas content by measuring the desorption behavior of on-site drilling cores or representative cuttings. The indirect method is to obtain the content of adsorbed gas and free gas respectively through isothermal adsorption experimental simulation and logging interpretation. Summary of the invention

[0005] In order to more accurately characterize the producing degree of shale gas reservoirs and increase the selection space, a method, device and equipment for characterizing the producing degree of shale gas reservoirs are provided in an embodiment of the present invention.

[0006] In a first aspect, an embodiment of the present invention provides a method for characterizing the producing degree of a shale gas reservoir, which may include:

[0007] Based on the influence of reservoir matrix desorption and slippage effect on shale gas reservoir production volume, the first influencing factor on shale gas reservoir production degree is determined;

[0008] Based on the influence of reservoir fracture morphology parameters and transformation zone parameters on the production rate of shale gas reservoirs, the second influencing factor on the production degree of shale gas reservoirs is determined;

[0009] Based on the first influencing factor and the second influencing factor, the production capacity of the shale gas reservoir established based on the wavefront rapid advancement method is predicted to characterize the production degree of the shale gas reservoir.

[0010] Optionally, the process of establishing the productivity model of the shale gas reservoir may include:

[0011] Determine the front edge position of the pressure wave at each moment based on the wavefront rapid advancement method, so as to use the front edge position of the pressure wave as the outer boundary condition for pressure prediction;

[0012] Based on the outer boundary conditions and the bottom hole pressure, determining the gas seepage relationship of each grid divided by the shale gas reservoir to establish a material balance equation group of the grid;

[0013] The material balance equations are solved to determine the pseudo-pressure distribution of the shale gas reservoir, and the pseudo-pressure distribution is used as the real pressure distribution of the shale gas reservoir to determine the production capacity of the shale gas reservoir.

[0014] Optionally, establishing the production capacity of the shale gas reservoir based on the actual pressure distribution of the shale gas reservoir may include:

[0015] Determining the amount of gas produced by free gas desorption in the matrix in each grid based on the true pressure distribution;

[0016] Determining the amount of gas produced by free gas expansion in the matrix pores in each grid based on the true pressure distribution;

[0017] Determine the amount of gas produced by fracture compression in each grid based on the true pressure distribution;

[0018] Determining the amount of gas produced by matrix compression in each grid based on the true pressure distribution;

[0019] The production capacity of the shale gas reservoir is determined based on the amount of gas produced by free gas desorption in the matrix in each grid, the amount of gas produced by free gas expansion in the matrix pores, the amount of gas produced by fracture compression and the amount of gas produced by matrix compression.

[0020] Optionally, determining the amount of gas produced by crack compression in each grid based on the true pressure distribution may include:

[0021] Determine the amount of gas produced by free gas expansion in the artificial fractures in each grid based on the true pressure distribution;

[0022] Determine the amount of gas produced by free gas expansion in the natural fractures in each grid based on the true pressure distribution;

[0023] Based on the amount of gas produced by free gas expansion in the artificial fractures in each grid and the amount of gas produced by free gas expansion in the natural fractures in each grid, the amount of gas produced by fracture compression in each grid is determined.

[0024] Optionally, before determining the first influencing factor on the producing degree of shale gas reservoir, the following steps may also be included:

[0025] Based on the wavefront migration equation, the effects of desorption and slippage of the reservoir matrix on the producing volume of shale gas reservoirs are determined, the effects of desorption of the reservoir matrix on the producing volume of shale gas reservoirs are determined, the effects of slippage effect of the reservoir matrix on the producing volume of shale gas reservoirs are determined, and the effects of no desorption and no slippage effect of the reservoir matrix on the producing volume of shale gas reservoirs are determined.

[0026] Optionally, the fracture morphology parameters of the reservoir and the transformed zone parameters may include: fracturing stage, permeability of the transformed zone, fracture length, fracture network structure type and natural fracture conductivity.

[0027] Optionally, the determination of the second influencing factor on the producing degree of the shale gas reservoir may include:

[0028] Based on the effects of different fracturing stages on the production range of shale gas reservoirs and the reservoir production area-time curve, determining the influence factor of the fracturing stage on the production speed of shale gas reservoirs;

[0029] Based on the different permeabilities of the transformed area and the reservoir production area-time curve, the influencing factors of the permeability of the transformed area on the production speed of the shale gas reservoir are determined;

[0030] Based on the effects of different fracture lengths on the producing range of shale gas reservoirs and the reservoir producing area-time curve, determining the influencing factor of the fracture length on the producing speed of the shale gas reservoir;

[0031] Based on the effects of different fracture network structure types on the producing range of shale gas reservoirs and the reservoir producing area-time curve, the influencing factors of the fracture network structure type on the producing speed of shale gas reservoirs are determined; wherein the fracture network structure types include: surface fracture model, surface fracture + SRV combination model, fracture network model, and fracture network + SRV combination model;

[0032] Based on the effects of different natural fracture conductivity on the shale gas reservoir producing range and the reservoir producing area-time curve, determining the influencing factors of the natural fracture conductivity on the shale gas reservoir producing speed;

[0033] Based on the influence factor of the fracturing stage on the producing speed of the shale gas reservoir, the influence factor of the permeability of the transformed zone on the producing speed of the shale gas reservoir, the influence factor of the fracture length on the producing speed of the shale gas reservoir, the influence factor of the fracture network structure type on the producing speed of the shale gas reservoir and the influence factor of the natural fracture conductivity on the producing speed of the shale gas reservoir, the second influencing factor on the producing degree of the shale gas reservoir is determined.

[0034] In a second aspect, an embodiment of the present invention provides a device for characterizing the degree of production of a shale gas reservoir, which may include:

[0035] A first influencing factor determination module, for determining a first influencing factor on the producing degree of the shale gas reservoir based on the influence of the desorption and slippage effects of the reservoir matrix on the producing volume of the shale gas reservoir;

[0036] A second influencing factor determination module is used to determine a second influencing factor on the producing degree of the shale gas reservoir based on the influence of the fracture morphology parameters of the reservoir and the transformation zone parameters on the producing speed of the shale gas reservoir;

[0037] The production capacity prediction module is used to predict the production capacity of the established shale gas reservoir based on the first influencing factor and the second influencing factor to characterize the production degree of the shale gas reservoir.

[0038] In a third aspect, an embodiment of the present invention provides a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the method for characterizing the degree of production of a shale gas reservoir as described in the first aspect.

[0039] In a fourth aspect, an embodiment of the present invention provides a computer device, including a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein when the processor executes the program, the method for characterizing the degree of utilization of a shale gas reservoir as described in the first aspect is implemented.

[0040] The beneficial effects of the above technical solution provided by the embodiment of the present invention include at least:

[0041] The embodiment of the present invention provides a method, device and equipment for characterizing the degree of utilization of shale gas reservoirs. The method uses a high-precision wavefront rapid advancement method to predict the wavefront migration of shale gas reservoirs, and quantitatively gives the relationship between reservoir utilization and time; when using the high-precision wavefront rapid advancement method for calculation, the reservoir utilization range is larger within the same time; the application of the wavefront rapid advancement method in heterogeneous reservoirs is realized, and by confirming the influence of different transformation zones on reservoir utilization and the influence of reservoir heterogeneity on reservoir utilization, pressure prediction and production analysis within the utilization range are realized, thereby optimizing and improving the gas reservoir parameters for shale gas utilization.

[0042] Furthermore, different eikonal equations are constructed for fractures and matrix respectively to achieve the purpose of predicting the pressure wave front; using the composite linear model of multi-stage fracturing horizontal wells, different flow states are considered in different seepage areas, so that the simulation results are more consistent with reality.

[0043] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the written description and the accompanying drawings.

[0044] The technical solution of the present invention is further described in detail below through the accompanying drawings and embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0045] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings:

[0046] Figure 1 A schematic diagram of a flow chart of a method for characterizing the producing degree of a shale gas reservoir provided in an embodiment of the present invention;

[0047] Figure 2 A schematic flow chart of a detailed method for characterizing the producing degree of a shale gas reservoir provided in an embodiment of the present invention;

[0048] Figure 3 The relationship between reservoir production and time under different conditions corresponding to the desorption and slippage effects provided in the embodiments of the present invention;

[0049] Figure 4 The relationship curve between the reservoir producing volume and the pseudo-time corresponding to the desorption and slippage effects provided in the embodiment of the present invention;

[0050] Figure 5 The reservoir producing ranges of different fracturing stages provided in the embodiments of the present invention;

[0051] Figure 6 Reservoir production curves of different fracturing stages provided in the embodiments of the present invention;

[0052] Figure 7 The reservoir producing range of different transformation zone permeabilities provided in the embodiments of the present invention;

[0053] Figure 8 The reservoir producing curves of different transformation zone permeabilities provided in the embodiments of the present invention;

[0054] Fig. 9 The reservoir producing ranges of different fracture lengths provided in the embodiments of the present invention;

[0055] Fig.10 Reservoir production curves of different fracture lengths provided in an embodiment of the present invention;

[0056] Fig.11The reservoir producing range under different models provided in the embodiments of the present invention;

[0057] Fig.12 Reservoir production curves under different models provided in the embodiments of the present invention;

[0058] Fig.13 The producing range of reservoirs with different natural fracture conductivity provided in the embodiments of the present invention;

[0059] Fig.14 Reservoir producing curves with different natural fracture conductivity provided in the embodiments of the present invention;

[0060] Fig.15 A schematic diagram of the flow of gas in a grid provided in an embodiment of the present invention;

[0061] Fig.16 A schematic diagram of a seam network model provided in an embodiment of the present invention;

[0062] Fig.17 A reservoir pressure distribution diagram provided in an embodiment of the present invention;

[0063] Fig.18 A curve showing the relationship between the activation range and time provided in an embodiment of the present invention;

[0064] Fig.19 The yield and time relationship curve provided in the embodiment of the present invention;

[0065] Fig. 20 A curve showing the relationship between daily production and time provided in an embodiment of the present invention;

[0066] Fig.21 is the gas supply ratio provided in the embodiment of the present invention;

[0067] Fig. 22 A double logarithmic curve provided in an embodiment of the present invention;

[0068] Fig.23 A reservoir pressure distribution diagram provided in an embodiment of the present invention;

[0069] Fig.24 A comparison diagram of producing degrees at half lengths of different artificial fractures provided in an embodiment of the present invention;

[0070] Fig.25 It is a schematic diagram of the structure of a device for characterizing the producing degree of a shale gas reservoir provided in an embodiment of the present invention. DETAILED DESCRIPTION

[0071] The exemplary embodiments of the present disclosure will be described in more detail below with reference to the accompanying drawings. Although the exemplary embodiments of the present disclosure are shown in the accompanying drawings, it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments set forth herein. On the contrary, these embodiments are provided to enable a more thorough understanding of the present disclosure and to fully convey the scope of the present disclosure to those skilled in the art.

[0072] The inventors found that the existence of critical desorption pressure causes the desorption phenomenon to lag, which is an important parameter that cannot be ignored; for the early stage of production, it is reasonable to set the gas compression coefficient to a constant value when calculating the expansion of the seepage area and the desorption area, but for long-term dynamic analysis and production prediction, the change of the gas compression coefficient cannot be ignored. Therefore, it is necessary to find a method to characterize the degree of shale gas reservoir utilization to provide theoretical and technical support for the effective development of shale reservoirs.

[0073] The physical meanings of the parameters involved in the embodiments of the present invention are as follows:

[0074] Q-permeate flow, m 3 / s;

[0075] KA-permeability, m / s;

[0076] Z a - Pseudo-compression factor;

[0077] t a - Pseudo-time;

[0078] P a - Pseudo pressure, MPa;

[0079] T-formation (reservoir) temperature, °C;

[0080] △H-grid height, m;

[0081] △L-division grid side length, m;

[0082] G d -The amount of gas extracted by gas desorption, m 3 ;

[0083] ρ b -Gas density at the current moment, kg / m 3 ;

[0084] h-effective reservoir thickness, m;

[0085] V L -Langmuir volume, m 3 ·m -3 ;

[0086] F L-Langmuir pressure, MPa;

[0087] p i -Original formation (reservoir) pressure, MPa;

[0088] p-formation pressure at the current moment, MPa;

[0089] p L - Rankine pressure, MPa;

[0090] G m -The amount of gas produced by the expansion of free gas in the matrix pores, m 3 ;

[0091] φ m -matrix porosity, %;

[0092] T sc -Temperature under standard conditions, °C;

[0093] p sc -Pressure under standard conditions, MPa;

[0094] Z i -Gas compressibility factor in its original state;

[0095] Z-gas compression factor at the current moment;

[0096] G hf -The amount of gas produced by the expansion of free gas in artificial fractures, m 3 ;

[0097] V hf - Volume of hydraulic fracture, m 3 ;

[0098] v hf - porosity of hydraulic fractures, %;

[0099] G nf -Amount of gas produced by free gas expansion in natural fractures, m 3 ;

[0100] V nf - Volume of natural fractures, m 3 ;

[0101] φ nf - porosity of natural fractures, %;

[0102] V f - Volume of total fractures (hydraulic + natural), m 3 ;

[0103] C f -Compression factor of total fractures (hydraulic + natural);

[0104] V m - Volume of the matrix, m 3 ;

[0105] C m - compressibility of the matrix;

[0106] C t -Comprehensive compression factor;

[0107] C m - compressibility of the matrix;

[0108] C g -Compressibility factor of the gas;

[0109] C d - desorption compressibility factor;

[0110] α-tangential momentum supply coefficient, ranging from -0 to 1;

[0111] μ g - gas viscosity;

[0112] q m -The amount of gas provided by the matrix to the fracture per unit volume per unit time;

[0113] r - matrix pore radius;

[0114] ρi - original density of the gas;

[0115] M-relative molecular mass of reservoir gas.

[0116] In view of the above problems, an embodiment of the present invention proposes a method for characterizing the degree of production of shale gas reservoirs that overcomes the above problems or at least partially solves the above problems. Figure 1 As shown, the method may include the following steps:

[0117] Step S11: determining a first influencing factor on the producing degree of the shale gas reservoir based on the influence of the desorption and slippage effects of the reservoir matrix on the producing volume of the shale gas reservoir.

[0118] Step S12: Determine a second influencing factor on the production degree of the shale gas reservoir based on the influence of the fracture morphology parameters of the reservoir and the transformation zone parameters on the production speed of the shale gas reservoir. The fracture morphology parameters and transformation zone parameters in the embodiment of the present invention include but are not limited to: fracturing stage, permeability of the transformation zone, fracture length, fracture network structure type and natural fracture conductivity.

[0119] Step S13: Based on the first influencing factor and the second influencing factor, the productivity of the shale gas reservoir established based on the wavefront rapid advancement method is predicted to characterize the production degree of the shale gas reservoir.

[0120] The embodiment of the present invention studies the effects of desorption and slippage on reservoir production, the effects of fracture morphology and transformation zone on reservoir production, and realizes pressure prediction and production analysis within the production range. It should be noted that the first influencing factor in the embodiment of the present invention refers to the effects of desorption and slippage on reservoir production, and the second influencing factor is the effects of fracture morphology parameters and transformation zone parameters on reservoir production, which lays the foundation for parameter selection for subsequent shale gas reservoir production capacity.

[0121] The embodiment of the present invention uses a high-precision wavefront rapid advancement method to predict the wavefront migration of a shale gas reservoir, and quantitatively gives the relationship between reservoir production and time; when using the high-precision wavefront rapid advancement method for calculation, the reservoir production range is larger within the same time; the application of the wavefront rapid advancement method in heterogeneous reservoirs is realized, and by confirming the impact of different transformation zones on reservoir production, as well as the impact of reservoir heterogeneity on reservoir production, pressure prediction and production analysis within the reservoir production range are realized, thereby optimizing and improving the gas reservoir parameters for shale gas production.

[0122] In a detailed embodiment, referring to Figure 2 As shown, the method for characterizing the producing degree of shale gas reservoir may specifically include the following steps:

[0123] Step S201: based on the wavefront migration function equation, respectively determine the influence of the desorption effect and the slippage effect of the reservoir matrix on the producing volume of the shale gas reservoir, determine the influence of the desorption effect of the reservoir matrix on the producing volume of the shale gas reservoir, determine the influence of the slippage effect of the reservoir matrix on the producing volume of the shale gas reservoir, and determine the influence of no desorption effect and no slippage effect of the reservoir matrix on the producing volume of the shale gas reservoir.

[0124] In order to determine the influence of desorption and slippage effect of shale gas reservoir matrix on reservoir production in the embodiment of the present invention, the reservoir parameters are adjusted as follows, as shown in Table 1:

[0125] Table 1 Wavefront migration function equations under different conditions

[0126]

[0127] According to Table 1, we can get Figure 3 The relationship between reservoir production and time under different conditions (desorption and slippage effect) is shown in Figure 2. Figure 1 . Figure 1 The light gray area, dark gray area, and gray area in the figure represent the propagation range of the pressure wave after 3 months, 3 years, and 30 years of gas reservoir development, respectively.

[0128] Step S202: determining a first influencing factor on the producing degree of the shale gas reservoir based on the influence of the desorption and slippage effects of the reservoir matrix on the producing volume of the shale gas reservoir.

[0129] Combination Figure 4 From the relationship curve between the mobilization volume and time shown, it can be found that the slippage effect has a great influence on the reservoir mobilization. When the slippage effect is considered, the reservoir mobilization volume is larger than that when the slippage effect is not considered; while the effect of desorption on the reservoir mobilization is very small. When the matrix desorption is considered, the reservoir mobilization degree is smaller than that when the desorption is not considered.

[0130] Step S203: determining the influence factor of the fracturing stage on the producing speed of the shale gas reservoir based on the producing range of the shale gas reservoir with different fracturing stages and the producing area-time curve of the reservoir.

[0131] In the embodiment of the present invention, steps S203 to S208 analyze the factors affecting reservoir production for the reformed zone model and the fracture network model respectively. The reservoir parameters used are shown in Table 2 as follows:

[0132] Table 2 Reservoir parameters

[0133]

[0134] Multi-stage fracturing horizontal wells are now widely used in the exploitation of shale gas reservoirs, so it is very necessary to study the impact of fracturing technology on reservoir development. This step studies the impact of fracturing stages on reservoir development for a horizontal well length of 1000m, a reformed zone permeability 10 times that of ordinary matrix permeability, and fracturing stages of 5, 10, and 15, respectively.

[0135] from Figure 5 and Figure 6 It can be seen that the influence of the fracturing level on the reservoir production speed is very large, especially before the pressure wave propagates to the boundary of the transformation zone, the reservoir production situation shows a great difference. When the fracturing level is 5, the reservoir production is the slowest, and the impact of the transformation zone boundary lasts the longest. The pressure wave can only propagate to the boundary of the transformation zone in 150 days. When the fracturing level is 10, the production speed of the transformation zone increases rapidly, and the pressure wave only needs 80 days to propagate to the boundary of the transformation zone, and then the reservoir production speed decreases rapidly. When the fracturing level increases to 15, the reservoir production speed increases less than that of the case where the fracturing level is 10. At this time, the reservoir production speed is the fastest, but after the pressure wave propagates to the boundary of the transformation zone, the reservoir production speed is not much different from the case where the pressure level is 10.

[0136] Step S204: determining the influencing factor of the permeability of the transformed area on the producing speed of the shale gas reservoir based on the different permeabilities of the transformed area on the producing range of the shale gas reservoir and the reservoir producing area-time curve.

[0137] In order to simplify the complex formation conditions in the near-wellbore area, this step uses a simplified SRV (tight oil reservoir transformation area) to describe the complex conditions of the transformation area. Therefore, the permeability of the transformation area has a very direct impact on the production of the reservoir. In the embodiment of the present invention, the permeability of the transformation area is 2, 5, and 10 times the permeability of the ordinary matrix when the fracturing stage is 10. The reservoir production conditions are studied respectively. The permeabilities inside the transformation area are 10.42×10 -6 μm 2 ,26.05×10 -6 μm 2 and 52.1×10 -6 μm 2 .

[0138] Reference Figure 7 and Figure 8 As shown in Figure 2, the permeability inside the reformed area has a great impact on reservoir production, and it mainly occurs before the pressure wave propagates to the boundary of the reformed area. The lower the permeability inside the reformed area, the slower the reservoir production and the longer the duration of the impact of the reformed area boundary. When K srv =10.42×10 -6 μm 2 When K srv =26.05×10 -6 μm 2 When K srv =52.1×10 -6 μm 2 When the pressure wave propagates to the boundary of the reformed area, the difference in reservoir production speed under different reformed area permeabilities decreases.

[0139] Step S205: Determine the influence factor of fracture length on shale gas reservoir producing speed based on the effects of different fracture lengths on shale gas reservoir producing range and reservoir producing area-time curve.

[0140] In the actual production process, the length of the fracture will be adjusted according to the specific situation to achieve the best production state. The length of the fracture directly affects the size of the reservoir transformation area. In the embodiment of the invention, for the fracture lengths of 200m, 300m, 400m, and 500m, the corresponding transformation area is 0.2km 2 , 0.3km 2 , 0.4km 2 and 0.5km 2 The permeability inside the transformation area is 52.1×10 -6 μm 2 This is used to compare the effect of fracture length on reservoir production.

[0141] Reference Fig. 9 and Fig.10 As shown in the figure, the influence of fracture length on reservoir production is very large. At the beginning of reservoir development, different fracture lengths have no effect on reservoir production, because the pressure wave has not yet propagated to the end of the fracture. On the 7th day, the curves of fracture length 500m and fracture length 200m diverge, which shows that the pressure wave has propagated to the boundary of the transformation area through the fracture. After the pressure wave propagates to the boundary of the transformation area, the reservoir production speed decreases rapidly, and at the same time, the increase in the production area is proportional to the increase in the fracture length, and the production area is linearly related to the square root of time.

[0142] Step S206, based on the effects of different fracture network structure types on the producing range of shale gas reservoirs and the reservoir producing area-time curve, determine the influencing factors of the fracture network structure type on the producing speed of the shale gas reservoir; wherein the fracture network structure types include: surface fracture model, surface fracture + SRV combination model, fracture network model, and fracture network + SRV combination model.

[0143] In the actual fracturing process, artificial fractures are connected with natural fractures in the formation to form an intricate fracture network structure. In the embodiments of the invention, the reservoir production under the fracture network model and the SRV model are studied based on the simple surface fracture model, the combination of surface fracture and SRV, the fracture network model, and the combination of fracture network and SRV. The reservoir production under different conditions is studied. The permeability inside the reformed area is 52.1×10 -6 μm 2 , the spacing of the fracture network model is 20m and 50m respectively.

[0144] Reference Fig.11 and Fig.12As shown in the figure, the reservoir production speed of the ordinary surface fracture model is much slower than that of the surface fracture + SRV model, while the production speed of the fracture network model with a fracture spacing of 50m is very close to that of the surface fracture + SRV model, so the production speed of the fracture network is much greater than that of the ordinary surface fracture. When the fracture network spacing is 50m + SRV, the reservoir production speed is greatly improved compared with the case of only fracture network, and when the fracture network spacing is 20m, the reservoir production speed is greater than the case of fracture spacing of 50m + SRV. When SRV exists at the same time, the reservoir production speed does not increase significantly, but is very close. Moreover, when the pressure wave propagates to the outside of the reformed area, the reservoir production speed decreases rapidly, and the production speed of the fracture network model and the fracture network + SRV model is not much different.

[0145] Step S207: determining the influencing factors of natural fracture conductivity on shale gas reservoir producing speed based on the effects of different natural fracture conductivity on shale gas reservoir producing range and reservoir producing area-time curve.

[0146] In the actual fracturing process, artificial fractures are interconnected with natural fractures, but proppant cannot effectively support all fractures, so the conductivity of natural fractures and artificial fractures may be very different. In the embodiment of the invention, the conductivity of artificial fractures is 100×10 -3 μm 2 m model, the conductivity of natural fractures is studied as 10×10 -3 μm 2 m, 20×10 -3 μm 2 m, 50×10 -3 μm 2 m and 100×10 -3 μm 2 The production status of the reservoir at time m.

[0147] Reference Fig.13 and Fig.14 As shown in the figure, the influence of the conductivity of natural fractures on reservoir production is relatively small. Since the production speed of the fracture network is much faster than that of the surface fractures, in the fracture network model, the influence of the conductivity of natural fractures on production is not significant. This shows that natural fractures provide a fast channel for the propagation of pressure waves. Even if the conductivity of natural fractures is greatly reduced, it still has a great advantage over the matrix system. Fig.14 It can be seen that the greater the conductivity of the natural fracture, the faster the reservoir is produced. However, when the conductivity increases from 50×10 -3 μm 2 m increases to 100×10 -3 μm 2m, the reservoir production does not increase much, but when the conductivity of natural fractures increases from 10×10 -3 μm 2 m rises to 20×10 -3 μm 2 m, the reservoir production increases more.

[0148] Step S208, determine the second influencing factor on the producing degree of shale gas reservoir based on the influencing factor of fracturing stage on the producing rate of shale gas reservoir, the influencing factor of permeability of transformation zone on the producing rate of shale gas reservoir, the influencing factor of fracture length on the producing rate of shale gas reservoir, the influencing factor of fracture network structure type on the producing rate of shale gas reservoir and the influencing factor of natural fracture conductivity on the producing rate of shale gas reservoir.

[0149] From the above steps S203 to S207, it can be seen that large-scale fracturing is required when exploiting shale reservoirs. Artificial fractures and natural fractures in the reservoir are interconnected to form a complex fracture network structure, which increases the difficulty of predicting the production capacity of shale gas reservoirs. However, realizing the production capacity prediction of the fracture network model of shale gas reservoirs is of great significance for guiding the development of gas reservoirs. Based on previous research results, the pressure front is used as the outer boundary condition for pressure prediction, so as to predict the pressure distribution inside the entire producing area, obtain the cumulative gas production of the reservoir and the production rate of the gas well, and the contribution ratio of the compression effect of desorbed gas, free gas and matrix fractures to the gas well production.

[0150] Step S209: determine the position of the pressure wave front at each moment based on the wavefront rapid advancement method, so as to use the pressure wave front position as the outer boundary condition for pressure prediction.

[0151] In this step, the Fast Marching Method (FMM) can be used to obtain the position of the pressure wave front at each moment. Assuming that the pressure in the reservoir is balanced at each moment, the internal pressure of the reservoir can be predicted based on the boundary pressure and bottom hole pressure.

[0152] Step S210: Based on the outer boundary conditions and the bottom hole pressure, determine the gas seepage relationship of each grid divided into shale gas reservoirs to establish a material balance equation group of the grids.

[0153] The flow of gas in the grid can be referred to Fig.15 As shown, assuming that there is only flow in the X and Y directions between the grids, the percolation equation of the gas in one-dimensional flow is shown as follows with reference to formula (1):

[0154]

[0155] Since it is assumed that the pressure in the reservoir is stable at each time point, the inflow in grid i, j is 0 at each time point. Therefore, the material balance equation of grid i, j can be established as shown in formula (2):

[0156] Q i-1，j +Q i+1，j +Q i，j-1 +Q i，j+1 =0 Formula (2)

[0157] According to the above formula (1) and formula (2), formula (3) can be obtained as follows:

[0158]

[0159] For each grid in the reservoir, the corresponding equations are listed and the equation group is solved to obtain the pseudo-pressure distribution in the reservoir, and then the pseudo-pressure is converted into the real formation pressure to obtain the real pressure distribution in the reservoir. After obtaining the pressure of each grid, the gas production in each grid can be obtained according to the pressure of the grid, as shown in the following step S211.

[0160] Step S211, solving the material balance equations to determine the pseudo-pressure distribution of the shale gas reservoir, and using the pseudo-pressure distribution as the real pressure distribution of the shale gas reservoir to determine the production capacity of the shale gas reservoir.

[0161] Specifically, the production capacity of shale gas reservoirs based on the actual pressure distribution of shale gas reservoirs may include the following aspects:

[0162] (1) The amount of gas produced by desorption of free gas in the matrix in each grid is determined based on the true pressure distribution. The amount of gas produced by desorption of gas in the grid is shown in Formula (4) as follows:

[0163]

[0164] (2) The amount of gas produced by the expansion of free gas in the matrix pores in each grid is determined based on the true pressure distribution. The amount of gas produced by the expansion of free gas in the matrix pores is shown as follows with reference to formula (5):

[0165]

[0166] (3) Determine the amount of gas produced by fracture compression in each grid based on the true pressure distribution.

[0167] (3.1) The amount of gas produced by free gas expansion in the artificial fractures in each grid is determined based on the real pressure distribution. The amount of gas produced by free gas expansion in the artificial fractures is shown in formula (6) as follows:

[0168]

[0169] (3.2) The amount of gas produced by free gas expansion in the natural fractures in each grid is determined based on the true pressure distribution. The amount of gas produced by free gas expansion in the natural fractures is shown in Formula (7) as follows:

[0170]

[0171] (3.3) Based on the gas volume produced by free gas expansion in the artificial fractures in each grid and the gas volume produced by free gas expansion in the natural fractures, the gas volume produced by fracture compression in each grid is determined. The gas volume produced by fracture compression is shown in Formula (8) as follows:

[0172]

[0173] (4) The amount of gas produced by matrix compression in each grid is determined based on the true pressure distribution. The amount of gas produced by matrix compression is shown in Formula (9) as follows:

[0174]

[0175] (5) Determine the production capacity of the shale gas reservoir based on the amount of gas produced by free gas desorption in the matrix, the amount of gas produced by free gas expansion in the matrix pores, the amount of gas produced by fracture compression, and the amount of gas produced by matrix compression in each grid.

[0176] The gas production is calculated in the corresponding grids respectively, and then the gas production of all grids in the utilization area is added together to obtain the total gas production at a certain moment.

[0177] When constructing the fracture network model, it is assumed that some natural fractures in the formation are connected with artificial fractures, while some fractures are not connected with artificial fractures. The natural fractures that are not connected with artificial fractures and the matrix are regarded as a unified system and represented by a unified apparent permeability. The complex fracture network model constructed is based on Fig.16 As shown, it is assumed that there is linear flow in the yellow area adjacent to the fracture network in the figure, while the flow in the reservoir away from the fracture network is radial flow.

[0178] According to the reservoir parameters in Table 2, the pressure distribution of the reservoir after 1 month, 1 year, 5 years and 8 years of development is obtained. Fig.17 As shown, from Fig.17It can be seen that in the early stage of reservoir development, the pressure drop in the reservoir mainly occurs in the fractures, and when the reservoir is developed for one year, the pressure between the fractures begins to connect with each other, and the pressure wave area at this time is still limited to the vicinity of the fracture network. When the reservoir is developed to the fifth year, the pressure between the fractures has reached complete connection. According to the pressure distribution in the reservoir in the fifth and eighth years, it can be seen that near the pressure front, the reservoir pressure drops very quickly, while inside the producing area, the reservoir pressure is very low. This shows that in the middle and late stages of reservoir development, the pressure drop mainly occurs near the pressure wave front.

[0179] Fig.18 is the relationship curve between the reservoir production area and time. Fig.18 It can be seen that in the early stage of reservoir development, the reservoir utilization range expanded rapidly, but as time went on, the reservoir utilization became slower and slower. When the gas well was in production for the eighth year, the reservoir utilization range was 0.86 km 2 .

[0180] from Fig.19 It can be seen that the free gas in the matrix contributes the most to the total production. The contribution of the desorbed gas in the matrix is ​​lower than that of the free gas in the matrix, but higher than that of the free gas in the compression and fractures. When the gas well is in production for the eighth year, the cumulative total production of the gas well reaches 115 million m 3 , and the contribution of free gas in the matrix reached 89.57 million m 3 , accounting for 77.9% of the total gas supply. At this time, the contributions of desorbed gas, free gas in cracks, and compression are 15.42 million m 3 , 5.86 million m 3 and 4.19 million m 3 , accounting for 13.4%, 5.1% and 3.6% of the total gas production respectively.

[0181] right Fig.19 The curve in is derived to obtain the total gas production rate and the gas production rate of each factor at different times. The results are shown in Fig. 20 ,from Fig. 20 It can be seen that the total gas production rate of the gas well is consistent with the L-shaped curve commonly seen in shale gas wells. When the gas well just starts production, the daily production can reach 300,000 m 3 / d, and then the gas production rate of the gas well dropped rapidly. When the gas well was in production for one year, the gas production rate began to decline slowly. When the production reached the eighth year, the daily production of the gas well dropped to 5000m 3 / d. However, the gas supply rate of the desorption of gas in the matrix and the free gas and compression in the fractures has always been very small, and the gas supply rate of the free gas in the matrix is ​​consistent with the trend of the total production rate.

[0182] Fig.21is the gas supply ratio of each factor to the reservoir at different times, from Fig.21 It can be seen that the gas supply ratio of free gas in the matrix gradually decreases and finally tends to be flat, dropping to about 75%. The gas supply ratios of desorption, crack free gas and compression gradually increase and finally reach stability.

[0183] The double logarithmic curve is obtained from the production rate curve. Fig. 22 and Fig.23 It can be seen that the production process of the gas well can be divided into three stages, and the corresponding time nodes are 255 days and 1000 days respectively. The reservoir pressure diagrams corresponding to the corresponding time are obtained respectively. Fig.24 It can be seen that when the gas well is produced for 255 days, the pressure between the fractures has just started to connect, and when the production reaches 1000 days, the pressure between the reservoir fractures has basically reached the connection. This shows that the three stages corresponding to the production process correspond to the pressure between the fractures before reaching the connection, the pressure between the fractures starts to connect to the connection period, and the pressure between the fractures after reaching the connection.

[0184] The above-mentioned method for characterizing the degree of shale gas reservoir production provided in the embodiment of the present invention studies the effects of desorption and slippage on reservoir production, and finds that the slippage effect has a great influence on the production volume, while the effect of desorption on reservoir production is very small; the slippage effect can accelerate the production speed of the reservoir, while the desorption effect of the matrix reduces the production speed of the reservoir.

[0185] The influence of fracture morphology parameters and transformation zone parameters on reservoir production was studied. With the increase of fracturing levels, reservoir production becomes faster and faster, but the increase in reservoir production will become smaller and smaller; the higher the permeability in the transformation zone, the faster the reservoir production, but the increase in reservoir production will become smaller; the fracture length has a great influence on reservoir production, and the range of reservoir production increases linearly with the growth of fractures; the production speed of the fracture network model is close to that of the SRV model, but the production speed of the surface fracture model is very low, and when the fracture network spacing is reduced, the production gap between the fracture network model and the fracture network + SRV model will become smaller; under the fracture network model, the conductivity of natural fractures has little effect on reservoir production, even if the conductivity of the fractures is reduced by 10 times, the range of reservoir production will still change slightly;

[0186] The above method provided by the embodiment of the present invention realizes pressure prediction and production analysis within the utilization range. In the early stage of reservoir development, pressure drop mainly occurs inside the fracture. When the pressure wave propagates to the outside of the transformation area, the utilization speed of the reservoir drops rapidly, the pressure in the utilization area is very low, and the pressure drop at the utilization boundary is very large; the gas supply ratio of free gas in the matrix gradually decreases and finally tends to be flat, the gas supply ratio of desorption, fracture free gas and compression gradually increases, and finally reaches stability respectively, and the gas supply ratio of free gas in the matrix is ​​the largest; the production process of the gas well can be divided into three stages, corresponding to the pressure between the fractures before reaching the connection, the pressure between the fractures starts to be connected to the period of reaching the connection, and the pressure between the fractures after reaching the connection.

[0187] Based on the same inventive concept, a device for characterizing the degree of production of a shale gas reservoir is also provided in an embodiment of the present invention. Fig.25 As shown, the device may include: a first influencing factor determination module 11, a second influencing factor determination module 12 and a capacity prediction module 13, and its working principle is as follows:

[0188] The first influencing factor determination module 11 is used to determine the first influencing factor on the producing degree of the shale gas reservoir based on the influence of the desorption and slippage effects of the reservoir matrix on the producing volume of the shale gas reservoir;

[0189] The second influencing factor determination module 12 is used to determine the second influencing factor on the producing degree of the shale gas reservoir based on the influence of the fracture morphology parameters of the reservoir and the transformation zone parameters on the producing speed of the shale gas reservoir;

[0190] The production capacity prediction module 13 is used to predict the production capacity of the established shale gas reservoir based on the first influencing factor and the second influencing factor to characterize the production degree of the shale gas reservoir.

[0191] In an alternative embodiment, referring to Fig.25 As shown, the device may further include: a capacity model building module 14, the capacity model building module 14 is used to:

[0192] Determine the front edge position of the pressure wave at each moment based on the wavefront rapid advancement method, so as to use the front edge position of the pressure wave as the outer boundary condition for pressure prediction;

[0193] Based on the outer boundary conditions and the bottom hole pressure, determining the gas seepage relationship of each grid divided by the shale gas reservoir to establish a material balance equation group of the grid;

[0194] The material balance equations are solved to determine the pseudo-pressure distribution of the shale gas reservoir, and the pseudo-pressure distribution is used as the real pressure distribution of the shale gas reservoir to determine the production capacity of the shale gas reservoir.

[0195] In another optional embodiment, the production capacity prediction module 13 is specifically used for:

[0196] Determining the amount of gas produced by free gas desorption in the matrix in each grid based on the true pressure distribution;

[0197] Determining the amount of gas produced by free gas expansion in the matrix pores in each grid based on the true pressure distribution;

[0198] Determine the amount of gas produced by fracture compression in each grid based on the true pressure distribution;

[0199] Determining the amount of gas produced by matrix compression in each grid based on the true pressure distribution;

[0200] The production capacity of the shale gas reservoir is determined based on the amount of gas produced by free gas desorption in the matrix in each grid, the amount of gas produced by free gas expansion in the matrix pores, the amount of gas produced by fracture compression and the amount of gas produced by matrix compression.

[0201] In another optional embodiment, the production capacity prediction module 13 is specifically used for:

[0202] Determine the amount of gas produced by free gas expansion in the artificial fractures in each grid based on the true pressure distribution;

[0203] Determine the amount of gas produced by free gas expansion in the natural fractures in each grid based on the true pressure distribution;

[0204] Based on the amount of gas produced by free gas expansion in the artificial fractures in each grid and the amount of gas produced by free gas expansion in the natural fractures in each grid, the amount of gas produced by fracture compression in each grid is determined.

[0205] In another optional embodiment, the first influencing factor determination module 11 is specifically used to: determine the influence of the desorption effect and slippage effect of the reservoir matrix on the producing volume of the shale gas reservoir based on the wavefront migration function equation, determine the influence of the desorption effect of the reservoir matrix on the producing volume of the shale gas reservoir, determine the influence of the slippage effect of the reservoir matrix on the producing volume of the shale gas reservoir, and determine the influence of no desorption and no slippage effect of the reservoir matrix on the producing volume of the shale gas reservoir.

[0206] In another optional embodiment, the second impact factor determination module 12 is specifically used for:

[0207] Based on the effects of different fracturing stages on the production range of shale gas reservoirs and the reservoir production area-time curve, determining the influence factor of the fracturing stage on the production speed of shale gas reservoirs;

[0208] Based on the different permeabilities of the transformed area and the reservoir production area-time curve, the influencing factors of the permeability of the transformed area on the production speed of the shale gas reservoir are determined;

[0209] Based on the effects of different fracture lengths on the producing range of shale gas reservoirs and the reservoir producing area-time curve, determining the influencing factor of the fracture length on the producing speed of the shale gas reservoir;

[0210] Based on the effects of different fracture network structure types on the producing range of shale gas reservoirs and the reservoir producing area-time curve, the influencing factors of the fracture network structure type on the producing speed of shale gas reservoirs are determined; wherein the fracture network structure types include: surface fracture model, surface fracture + SRV combination model, fracture network model, and fracture network + SRV combination model;

[0211] Based on the effects of different natural fracture conductivity on the shale gas reservoir producing range and the reservoir producing area-time curve, determining the influencing factors of the natural fracture conductivity on the shale gas reservoir producing speed;

[0212] Based on the influence factor of the fracturing stage on the producing speed of the shale gas reservoir, the influence factor of the permeability of the transformed zone on the producing speed of the shale gas reservoir, the influence factor of the fracture length on the producing speed of the shale gas reservoir, the influence factor of the fracture network structure type on the producing speed of the shale gas reservoir and the influence factor of the natural fracture conductivity on the producing speed of the shale gas reservoir, the second influencing factor on the producing degree of the shale gas reservoir is determined.

[0213] Based on the same inventive concept, an embodiment of the present invention further provides a computer-readable storage medium on which a computer program is stored, and when the program is executed by a processor, the above-mentioned method for characterizing the degree of production of shale gas reservoirs is implemented.

[0214] Based on the same inventive concept, a computer device is also provided in an embodiment of the present invention, including a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the program, the above-mentioned method for characterizing the degree of utilization of shale gas reservoirs is implemented.

[0215] The principles of the problems solved by the above-mentioned devices, media, and related equipment in the embodiments of the present invention are similar to those of the above-mentioned methods, so their implementation can refer to the implementation of the above-mentioned methods, and the repeated parts will not be repeated.

[0216] Those skilled in the art will appreciate that embodiments of the present invention may be provided as methods, systems, or computer program products. Therefore, the present invention may take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware. Moreover, the present invention may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage and optical storage, etc.) containing computer-usable program code.

[0217] The present invention is described with reference to flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to embodiments of the present invention. It should be understood that each process and / or block in the flowchart and / or block diagram, as well as the combination of processes and / or blocks in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1 A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0218] These computer program instructions may also be stored in a computer-readable memory capable of directing a computer or other programmable data processing device to operate in a specific manner, so that the instructions stored in the computer-readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 A process or multiple processes and / or boxes Figure 1 A function specified in one or more boxes.

[0219] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions for implementing the process. Figure 1 A process or multiple processes and / or boxes Figure 1 The steps for the functions specified in one or more boxes.

[0220] Obviously, those skilled in the art can make various changes and modifications to the present invention without departing from the spirit and scope of the present invention. Thus, if these modifications and variations of the present invention fall within the scope of the claims of the present invention and their equivalents, the present invention is also intended to include these modifications and variations.

Claims

1. A method for characterizing the degree of production of shale gas reservoirs, characterized in that: include: Based on the influence of reservoir matrix desorption and slippage effect on the producing volume of shale gas reservoir, the first influencing factor on the producing degree of shale gas reservoir is determined; Based on the influence of reservoir fracture morphology parameters and transformation zone parameters on the production rate of shale gas reservoirs, the second influencing factor on the production degree of shale gas reservoirs is determined; Based on the first influencing factor and the second influencing factor, the production capacity of the shale gas reservoir established based on the wavefront rapid advancement method is predicted to characterize the production degree of the shale gas reservoir.

2. The method according to claim 1, characterized in that The process of establishing the productivity model of the shale gas reservoir includes: Determine the front edge position of the pressure wave at each moment based on the wavefront rapid advancement method, so as to use the front edge position of the pressure wave as the outer boundary condition for pressure prediction; Based on the outer boundary conditions and the bottom hole pressure, determining the gas seepage relationship of each grid divided by the shale gas reservoir to establish a material balance equation group of the grid; The material balance equations are solved to determine the pseudo-pressure distribution of the shale gas reservoir, and the pseudo-pressure distribution is used as the real pressure distribution of the shale gas reservoir to determine the production capacity of the shale gas reservoir.

3. The method according to claim 2, characterized in that Establishing the productivity of the shale gas reservoir based on the actual pressure distribution of the shale gas reservoir, including: Determining the amount of gas produced by free gas desorption in the matrix in each grid based on the true pressure distribution; Determining the amount of gas produced by free gas expansion in the matrix pores in each grid based on the true pressure distribution; Determine the amount of gas produced by fracture compression in each grid based on the true pressure distribution; Determining the amount of gas produced by matrix compression in each grid based on the true pressure distribution; The production capacity of the shale gas reservoir is determined based on the amount of gas produced by free gas desorption in the matrix in each grid, the amount of gas produced by free gas expansion in the matrix pores, the amount of gas produced by fracture compression and the amount of gas produced by matrix compression.

4. The method according to claim 3, characterized in that: Determining the amount of gas produced by fracture compression in each grid based on the true pressure distribution includes: Determine the amount of gas produced by free gas expansion in the artificial fractures in each grid based on the true pressure distribution; Determine the amount of gas produced by free gas expansion in the natural fractures in each grid based on the true pressure distribution; Based on the amount of gas produced by free gas expansion in the artificial fractures in each grid and the amount of gas produced by free gas expansion in the natural fractures in each grid, the amount of gas produced by fracture compression in each grid is determined.

5. The method according to any one of claims 1 to 4, characterized in that: Before determining the first influencing factor on the producing degree of shale gas reservoir, the method includes: Based on the wavefront migration equation, the effects of desorption and slippage of the reservoir matrix on the producing volume of shale gas reservoirs are determined, the effects of desorption of the reservoir matrix on the producing volume of shale gas reservoirs are determined, the effects of slippage effect of the reservoir matrix on the producing volume of shale gas reservoirs are determined, and the effects of no desorption and no slippage effect of the reservoir matrix on the producing volume of shale gas reservoirs are determined.

6. The method according to any one of claims 1 to 4, characterized in that: The fracture morphological parameters of the reservoir and the parameters of the reformed zone include: fracturing stage, permeability of the reformed zone, fracture length, fracture network structure type and natural fracture conductivity.

7. The method according to claim 6, characterized in that The second factor affecting the degree of production of shale gas reservoirs is determined, including: Based on the effects of different fracturing stages on the production range of shale gas reservoirs and the reservoir production area-time curve, determining the influence factor of the fracturing stage on the production speed of shale gas reservoirs; Based on the different permeabilities of the transformed area and the reservoir production area-time curve, the influencing factors of the permeability of the transformed area on the production speed of the shale gas reservoir are determined; Based on the effects of different fracture lengths on the producing range of shale gas reservoirs and the reservoir producing area-time curve, determining the influencing factor of the fracture length on the producing speed of the shale gas reservoir; Based on the effects of different fracture network structure types on the producing range of shale gas reservoirs and the reservoir producing area-time curve, the influencing factors of the fracture network structure type on the producing speed of shale gas reservoirs are determined; wherein the fracture network structure types include: surface fracture model, surface fracture + SRV combination model, fracture network model, and fracture network + SRV combination model; Based on the effects of different natural fracture conductivity on the shale gas reservoir producing range and the reservoir producing area-time curve, determining the influencing factors of the natural fracture conductivity on the shale gas reservoir producing speed; Based on the influence factor of the fracturing stage on the producing speed of the shale gas reservoir, the influence factor of the permeability of the transformed zone on the producing speed of the shale gas reservoir, the influence factor of the fracture length on the producing speed of the shale gas reservoir, the influence factor of the fracture network structure type on the producing speed of the shale gas reservoir and the influence factor of the natural fracture conductivity on the producing speed of the shale gas reservoir, the second influencing factor on the producing degree of the shale gas reservoir is determined.

8. A device for characterizing the degree of production of shale gas reservoirs, characterized in that: include: A first influencing factor determination module, for determining a first influencing factor on the producing degree of the shale gas reservoir based on the influence of the desorption and slippage effects of the reservoir matrix on the producing volume of the shale gas reservoir; A second influencing factor determination module is used to determine a second influencing factor on the producing degree of the shale gas reservoir based on the influence of the fracture morphology parameters of the reservoir and the transformation zone parameters on the producing speed of the shale gas reservoir; The production capacity prediction module is used to predict the production capacity of the established shale gas reservoir based on the first influencing factor and the second influencing factor to characterize the production degree of the shale gas reservoir.

9. A computer-readable storage medium having a computer program stored thereon, characterized in that: When the program is executed by a processor, the method for characterizing the producing degree of a shale gas reservoir as claimed in any one of claims 1 to 7 is implemented.

10. A computer device comprising a memory, a processor and a computer program stored in the memory and executable on the processor, characterized in that: When the processor executes the program, the method for characterizing the producing degree of a shale gas reservoir according to any one of claims 1 to 7 is implemented.

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