Method for determining hydraulic fracturing capacity of deep shale gas exploitation

Abstract

The invention belongs to the technical field of deep shale gas exploitation, and discloses a deep shale gas exploitation hydraulic fracturing productivity determination method, which comprises the following steps of: establishing a single-phase gas seepage model in a deep shale reservoir matrix area under the condition of considering bound water; establishing a gas-water two-phase seepage model of the deep shale reservoir transformation area considering the fracture hydraulic coupling behavior; and solving the established single-phase gas seepage model in the matrix area and the gas-water two-phase seepage model in the transformation area through a numerical simulation method to obtain the shale gas yield. According to the method, different equations are established according to structures and characteristics in different reservoir areas, and the accumulated yield of the deep shale reservoir can be accurately predicted.

Description

Technical Field

[0001] This invention belongs to the field of deep shale gas development technology and relates to a method for determining the hydraulic fracturing capacity of deep shale gas extraction. Background Technology

[0002] Shale gas is a type of natural gas existing in adsorbed or free states in natural shale reservoirs. It is an unconventional fossil energy source that combines high efficiency and cleanliness, with methane as its main component. Compared to traditional fossil fuels such as oil, it features lower combustion pollution and higher utilization efficiency, making it a relatively environmentally friendly energy source. Therefore, against the backdrop of the urgent need for global energy structure adjustment and transformation, the development and utilization of shale gas is receiving increasing attention from countries worldwide. Currently, in the development and utilization of shale gas, horizontal wells and hydraulic fracturing technologies are commonly used to effectively extract shale gas from shale reservoirs. Figure 1 The diagram shows a commonly used hydraulic fracturing method for shale gas extraction: by delivering fracturing fluid into the deep shale reservoir, the shale reservoir is fractured through perforation to generate hydraulic fracturing fractures and secondary fractures of various levels. These fractures then connect with natural fractures to form a fracturing zone, through which shale gas can flow through the fractures and diffuse through the matrix to reach the horizontal well and eventually reach the surface, enabling efficient development of shale gas.

[0003] To provide reliable information for early-stage gas field production capacity construction and later-stage production adjustments and optimizations, shale gas production capacity analysis is often required before extraction. Currently, many scholars simplify the fluid flow during shale gas extraction, considering the internal reservoir flow as single-phase gas flow and neglecting the impact of gas-water two-phase flow caused by moisture involvement. Therefore, their calculated daily gas production rate and cumulative seepage volume are higher than the corresponding values ​​measured in the field. While some scholars have considered gas-water two-phase flow, these are under normal conditions. However, in the high-temperature and high-pressure environment of deep reservoirs, coupling effects and multiphase seepage behavior have a greater impact on production; thus, the calculated daily gas production rate and cumulative seepage volume differ significantly from the corresponding values ​​measured in the field.

[0004] Therefore, how to provide an accurate method for determining the hydraulic fracturing capacity of deep shale gas extraction, in order to clarify the shale gas production capacity of deep shale reservoirs, is a technical problem that urgently needs to be solved. Summary of the Invention

[0005] The purpose of this invention is to address the shortcomings of existing production analysis and determination technologies, and to provide a method for determining the hydraulic fracturing production capacity of deep shale gas extraction that conforms to the seepage characteristics of deep shale reservoirs.

[0006] This invention is applicable to the analysis and determination of gas production in deep shale reservoirs. The invention divides hydraulically fracturing shale reservoirs into two regions: a matrix zone and a modified zone. The matrix zone, whose structure is almost unaffected by hydraulic fracturing, retains the natural shale properties. The matrix consists of shale matrix and natural fractures; therefore, the seepage flow within the matrix zone is divided into matrix seepage and fracture seepage. The modified zone, on the other hand, is composed of a complex, well-connected fracture network formed around the hydraulically fracturing fractures. The modified zone can be further divided into a matrix system and a fracture system. By establishing corresponding seepage models for both the matrix zone and the modified zone, a unified method is constructed, resulting in more accurate analysis and determination of the gas production.

[0007] This method, for the matrix zone, is based on the gas mass conservation and Darcy's law within the shale matrix. It incorporates the Langmuir equation to account for the desorption effect within the shale reservoir, treats fractures as thin layers with a certain stiffness, and introduces the stress-strain relationship of the natural fracture surface, considering the influence of fracture opening and closing on seepage. Combined with the changes in gas viscosity and density under high geothermal temperatures and porosity under high stress, a matrix-fracture coupled single-phase gas seepage mathematical model is obtained. For the modified zone, based on the two-phase seepage characteristics within the fracturing area, and according to the gas and water two-phase mass conservation and Darcy's law in the shale modified zone, the two-phase flow mechanism is described by considering capillary force curves and relative permeability models. Furthermore, based on the characteristics of gas-water two-phase seepage, the expressions for porosity changes under high stress and the stress-strain relationship of the natural fracture surface in the model are expanded to better suit two-phase flow conditions. The resulting matrix-fracture coupled multiphase seepage mathematical model is then obtained. Finally, through practical engineering applications, historical fitting is performed to verify the adaptability of the proposed mathematical model in actual engineering, and engineering feature optimization and capacity analysis are conducted to determine its effectiveness.

[0008] Based on the above analysis, the present invention provides a method for determining the hydraulic fracturing production capacity of deep shale gas extraction, comprising the following steps:

[0009] S1, Establish a single-phase gas flow model in the matrix zone of deep shale reservoirs considering bound water conditions; the single-phase gas flow model in the matrix zone includes a single-phase gas flow model in the matrix and a single-phase gas flow model in the fractures;

[0010] S2, Establish a gas-water two-phase flow model for deep shale reservoir stimulation zones that considers fracture hydraulic coupling behavior; the gas-water two-phase flow model for the stimulation zone includes a gas-water two-phase flow model for the matrix system and a gas-water two-phase flow model for the fracture system.

[0011] S3. The shale gas production is obtained by solving the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 using numerical simulation methods.

[0012] In step S2 above, the gas-water two-phase flow model of the matrix system includes a first gas phase mass balance equation and a first water phase mass balance equation; the gas-water two-phase flow model of the fracture system includes a second gas phase mass balance equation and a second water phase mass balance equation.

[0013] Step S3 above includes the following sub-steps:

[0014] S31. Set the initial values ​​of model parameters and boundary conditions for the area to be analyzed. Solve the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 using the finite element method. Perform a preliminary analysis of the predicted shale gas production in the area to be analyzed.

[0015] S32, based on the deviation between the preliminary analysis results of shale gas products and the fitting accuracy of historical production, the initial values ​​of the model parameters are corrected;

[0016] S33. Based on the corrected initial values ​​of model parameters and boundary conditions, the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 are solved again using the finite element method to obtain the shale gas production analysis results of the area to be analyzed.

[0017] In step S31 above, the initial pressures of the gas in the matrix system and fracture system within the modified area are considered as initial pressures, and the initial pressure of water is calculated based on the initial saturation. The pressure value at the horizontal well location in the area to be analyzed is the real-time bottom hole flowing pressure measured on-site.

[0018] In step S31 above, when solving the model, the boundary condition of the model is that the boundary of the region to be analyzed is a closed non-flowing boundary with horizontal and vertical geostress.

[0019] In step S32 above, the initial values ​​of the corrected model parameters include parameters such as the initial water saturation of the matrix zone, the initial water saturation of the modified zone, the initial opening of the hydraulic fracturing fractures, and the matrix permeability.

[0020] Compared with existing technologies, the method for determining the hydraulic fracturing production capacity of deep shale gas extraction provided by this invention has the following advantages:

[0021] This invention divides deep shale reservoirs into matrix zones and stimulated zones based on the structural characteristics of different regions. For the matrix zone, a single-phase gas flow model considering bound water conditions is constructed, and for the stimulated zone, a gas-water two-phase flow model considering fracture hydraulic coupling behavior is constructed. This improves the accuracy and effectiveness of cumulative production analysis for deep shale reservoirs. Attached Figure Description

[0022] Figure 1 This is a schematic diagram of existing shale gas hydraulic fracturing methods;

[0023] Figure 2 This is a flowchart of the method for determining deep shale gas production capacity according to an embodiment of the present invention;

[0024] Figure 3 This is a typical well bottom-hole flowing pressure curve measured in the field over 800 days according to an embodiment of the present invention;

[0025] Figure 4 This is a schematic diagram of the model and boundary conditions used in the embodiments of the present invention;

[0026] Figure 5 This is a comparison curve of daily gas production from a typical well simulation and actual field measurement in an embodiment of the present invention.

[0027] Figure 6 This is a comparison curve of the cumulative gas production of a typical well simulation and on-site measured gas production in an embodiment of the present invention. Detailed Implementation

[0028] The purpose of this invention is to address the shortcomings of existing production analysis and determination techniques by providing a method for determining shale gas production capacity that conforms to the seepage characteristics of deep shale reservoirs.

[0029] The analytical determination method of the present invention will be further described below through embodiments and accompanying drawings.

[0030] Example

[0031] This embodiment provides a method for determining the hydraulic fracturing production capacity of deep shale gas extraction, such as... Figure 2 As shown, it includes the following steps:

[0032] S1, Establish a single-phase gas flow model in the matrix zone of deep shale reservoirs under the condition of bound water; the single-phase gas flow model in the matrix zone includes a single-phase gas flow model in the matrix and a single-phase gas flow model in the fracture.

[0033] (a) Within the matrix

[0034] For the matrix, based on the conservation of mass in the shale matrix, and considering Langmuir gas desorption and gas flow satisfying Darcy's law, we can obtain: (1-1); in, The velocity of the solid particles is in m / s;

[0035] The relationship between reservoir volumetric deformation and effective porosity can be expressed using the small deformation principle, which yields the following: (1-2);

[0036] In addition, the high temperature and high pressure environment in deep shale reservoirs necessitates the following to accurately describe the relationship between gas density and temperature and pressure: (1-3);

[0037] Combining the above equations, we can obtain the single-phase gas flow model within the matrix considering bound water conditions as follows: (1-4); In the formula: The density of the gas within the matrix is ​​kg / m³. The effective porosity under the condition of bound water within the matrix; The molar mass of the gas is expressed in g / mol. The universal gas constant is J·mol⁻¹. -1 ·K -1 ; Temperature, K; Let mD be the matrix permeability. Where is the gas viscosity, Pa·s; g is the acceleration due to gravity; The Biot coefficient of the matrix; The gas density under standard conditions (0℃, 1 standard atmosphere (1 atm)) is expressed in kg / m³. 3 ; For volumetric strain; Let be the bulk modulus of the solid particle, in Pa; The gas pressure within the matrix is ​​expressed in Pa. The density is the matrix density, kg / m³. 3 ; m is the Langmuir volume constant. 3 / Kg; is the Langmuir pressure constant, in Pa.

[0038] The effective porosity under the condition of bound water in the matrix is ​​expressed as: (1-5); In the formula, For matrix porosity, Let be the bound water saturation within the matrix, and be a constant.

[0039] The bulk modulus of a solid particle is expressed as: K s =E / (3×(1-2v b )) (1-6); In the formula, E is the elastic modulus of the solid particle, and v b It is Poisson's ratio.

[0040] (ii) Inside the crack

[0041] For the fracture, based on the conservation of gas mass within the fracture, the change in gas transport within the fracture can be represented by the gas Darcy velocity and the fracture aperture, resulting in the following single-phase gas seepage model within the fracture: (1-7);

[0042] In the formula, The crack opening is expressed in meters (m). The pressure of the gas inside the crack is Pa; The density of the gas inside the crack is kg / m³. 3 ; denoted as crack permeability, mD; l is the dimension along the crack length, m.

[0043] Crack permeability is expressed as: (1-8);

[0044] In the formula, This is the crack roughness coefficient, which can be calculated based on the initial crack permeability conditions.

[0045] (III) Constitutive Equations

[0046] In deep shale gas reservoirs, due to high in-situ stress, reservoir deformation can significantly impact gas flow. Therefore, to account for porosity changes caused by reservoir deformation under deep conditions, and considering the assumption of small rock mass deformation and the effective stress principle, the stress-strain relationship of the reservoir matrix can be expressed as follows: (1-9); (1-10); (1-11); In the formula, The effective stress of the matrix is ​​Pa; It is the elastic stiffness tensor; For strain components; the four indices ijkl correspond to the two directions of stress (i,j) and the two directions of strain (k,l), respectively. The Biot coefficient of the matrix; It is the elastic stiffness tensor; Let m be the displacement component; The gas pressure within the matrix is ​​expressed in Pa. Let be the saturation of bound water within the matrix, which is a constant; , Unit tensor; For matrix porosity; The density of the water matrix, kg / m³ 3 ; The density is the matrix density, kg / m³. 3 ; The density of the gas is kg / m³. 3 .

[0047] Furthermore, fractures in the reservoir possess a certain stiffness. Therefore, as the stress on the matrix skeleton increases, the fracture aperture will also change, leading to variations in the fluid seepage velocity within the fractures. Thus, to effectively characterize the changes in fracture aperture within the reservoir during shale gas extraction and describe its stress-strain relationship, the relationship between fracture surface traction force, fracture stiffness, and fracture surface displacement is established: (1-12); In the formula, The traction force on the crack surface is kN; Here is the stiffness matrix of the crack surface; Let m be the jump displacement of the crack surface.

[0048] The natural boundary conditions applied at the discontinuity of the crack surface can be expressed as: (1-13); In the formula, is the unit vector of the crack surface; Let be the gas pressure inside the crack, in Pa.

[0049] The relationship between crack opening and jump displacement can be expressed by the following formula: (1-14); In the formula, The initial crack opening, m; n i It is the value of the normal vector n in the i direction, [u Ei [ ] represents the displacement of the crack surface.

[0050] Under high temperature and high pressure conditions in deep environments, the viscosity of free shale gas may differ significantly from that under normal conditions. Therefore, viscosity changes should not be ignored in high temperature and high pressure environments. In this embodiment, the viscosity of shale gas is expressed as: (1-15); (1-16); (1-17); (1-18); In the formula, ρ represents the gas viscosity in mPa·s; K, X, and Y are coefficients used in the calculation process.

[0051] S2, Establish a multiphase flow model for the deep shale reservoir stimulation zone considering the hydraulic coupling behavior of fractures; the multiphase flow model of the stimulation zone includes a gas-water two-phase flow model of the matrix system and a gas-water two-phase flow model of the fracture system.

[0052] (a) Matrix system

[0053] For the matrix system, the gas-water two-phase flow model includes the first gas phase mass balance equation and the first water phase mass balance equation.

[0054] Based on the principle of mass conservation in shale matrix, and considering Langmuir gas desorption, gas flow, and small deformation of the rock mass, the first gas phase mass balance equation in the matrix system can be obtained, expressed as: (2-1); In the formula, ρ is the density of the gas phase within the matrix, kg / m³; This represents the saturation of the gas phase within the matrix. Porosity of the matrix; The molar mass of the gas is expressed in g / mol. The universal gas constant is J·mol⁻¹. -1 ·K -1 ; Temperature, K; The gas pressure within the matrix is ​​expressed in Pa. Matrix permeability, mD; Where is the fluid viscosity, Pa·s; g is the acceleration due to gravity; The Biot coefficient of the matrix; For volumetric strain; Let be the bulk modulus of the solid particle, in Pa; The density is the matrix density, kg / m³. 3 ; The gas density under standard conditions (0℃, 1 standard atmosphere (1 atm)) is expressed in kg / m³. 3 ; m is the Langmuir volume constant. 3 / Kg; is the Langmuir pressure constant, in Pa.

[0055] Considering the mass conservation of the aqueous phase and Darcy flow, and establishing the relationship between the aqueous phase density and pressure using the compressibility coefficient, we can obtain: (2-2); In the formula, The density of the aqueous phase within the matrix (m) or crack (f) is expressed in kg / m³. Pa is the compressibility coefficient of the aqueous phase. -1 ; The pressure of the aqueous phase within the matrix or crack is Pa.

[0056] Similarly, based on the principle of mass conservation in shale matrix, and considering Langmuir's principle of water phase desorption, water phase flow, and small deformation of rock mass, the mass balance equation for the first water phase in the matrix system can be obtained, expressed as: (2-3); In the formula, The density of the aqueous phase within the matrix is ​​expressed in kg / m³. This represents the saturation level of the aqueous phase within the matrix. Pa is the compressibility coefficient of the aqueous phase. -1 ; The pressure of the aqueous phase within the matrix, in Pa; Porosity of the matrix; Matrix permeability, mD; Where is the viscosity of the aqueous phase, Pa·s; g is the acceleration due to gravity; The Biot coefficient of the matrix; For volumetric strain; Let be the bulk modulus of the solid particle, expressed in Pa.

[0057] (ii) Crack System

[0058] Inside a fracture, analyzing the compressible fluid within a single fracture from a microscopic perspective, according to the law of conservation of mass, the change in fluid flowing into or out of the fracture along the fracture direction, the source term of the fracture, and the change in fluid within the fracture over time should maintain equilibrium. Therefore, the condition that the fluid within a single fracture must satisfy can be expressed as: (2-4); In the formula, For fluid Density, kg / m³; Let be the average seepage velocity of the fluid along the length of the crack, in m / s; For fluid Saturation in the crack; The crack opening is expressed in meters (m). fluid caused by leakage in the crack Flowing source terms.

[0059] Assuming the crack length is much greater than the crack width, according to the cubic law of crack permeability, the average seepage velocity of the fluid along the crack length can be expressed as: (2-5); In the formula, This represents the average seepage velocity of the fluid in the crack, in m / s; The relative permeability of the fluid in the crack; The viscosity of a fluid is expressed in Pa·s. Let m be the dimension along the length of the crack. The crack opening is expressed in meters (m). This is the crack roughness coefficient, which can be calculated based on the initial crack permeability conditions. The average pore pressure of the fluid at the fracture surface.

[0060] For fracture systems, primarily hydraulic fracturing fractures, the relationship between fracture aperture and permeability is established using the cubic law of permeability. Permeability is expressed as: (2-6); In the formula: This is the crack roughness coefficient, which can be calculated based on the initial crack permeability conditions.

[0061] To express the amount of fluid leakage per unit area from cracks, Darcy's law can be used, as shown in the following formula: (2-7); In the formula, For porous media relative to fluid Penetration rate; This represents the pressure gradient between the crack and the porous medium.

[0062] Combining the above equations, we obtain the second gas phase mass balance equation for the fracture system: (2-8);

[0063] The second water phase mass balance equation in the fracture system is as follows: (2-9);

[0064] The effective saturation of water in a matrix system or fracture system can be expressed in the form of capillary pressure as follows: (2-10); In the formula: Effective water saturation within the matrix system (m) or crack system (f); The capillary pressure within the matrix system or fracture system, in Pa; ρ is the gas inlet pressure, Pa; z is the model parameter.

[0065] Here, both the aqueous and gas phases possess residual saturation, which also influences the two-phase flow during the simulation. The residual saturation of the gas and aqueous phases can be used to represent their respective saturation levels. .

[0066] , (2-11); , (2-12); In the formula, as medium Residual saturation of internal water; as medium Residual saturation of the internal gas phase.

[0067] Furthermore, assuming the residual saturation of the fluid is constant, the time derivatives of the saturation of water and gas satisfy the following relationship: (2-13);

[0068] The relative permeability of the gas and aqueous phases in a two-phase flow system, whether in a matrix system or a fractured system, is expressed as follows: (2-6); (2-7); In the formula: The relative permeability of the gas phase within the matrix or fracture system in a two-phase flow region; , A coefficient related to porous materials; The relative permeability of the aqueous phase within the matrix or fracture system in a two-phase flow region; Z represents the effective saturation of water within the matrix or fracture system, and z′ represents the model parameters.

[0069] (III) Constitutive Equations

[0070] In deep shale gas reservoirs, this may be more pronounced due to higher geostress. Furthermore, in addition to considering the porosity contribution of gas, the pore pressure of water must also be considered within the stirred-up reservoir due to the pressure difference between the water and gas phases during two-phase flow. Therefore, to account for the porosity changes caused by reservoir deformation under deep conditions, based on the assumption of small rock mass deformation, the stress-strain relationship of the rock matrix within the stirred-up reservoir can be expressed as: (2-14); (2-15); (2-16); (2-17); In the formula, , These represent the saturation levels of the gas and water phases within the matrix of the modified area, respectively.

[0071] By combining the above equations, the equilibrium equation within the matrix can be expressed as: (2-18); In the formula: For the effective stress of the matrix, It is the elastic stiffness tensor; For strain components; The Biot coefficient of the rock matrix. It is the elastic stiffness tensor; For displacement components; This refers to the gas pressure within the matrix; The water phase pressure within the matrix, , Unit tensor; For matrix porosity; , The saturation levels of the aqueous and gaseous phases; This represents the matrix density.

[0072] In deep-seated stirred-up reservoirs, under assumed conditions, the fractures possess a certain stiffness. Therefore, as the stress on the matrix skeleton increases, the fracture aperture also changes, leading to variations in the permeability of the gas and water phases, and consequently, changes in the flow velocities of the two phases within the fractures. Thus, to describe the stress-strain relationship at the fracture surface within the reservoir and obtain the relationship between fracture aperture and reservoir pressure, it is expressed as: (2-19); ; (2-20); In the formula: The traction force on the crack surface is kN; Here is the stiffness matrix of the crack surface; Let m be the jump displacement of the crack surface; It is the unit vector of the crack surface; It is the average pore pressure at the crack surface, in Pa. .

[0073] The relationship between crack opening and jump displacement is expressed as follows: (2-21); In the formula: It is the initial crack opening, m; [u Ei] is the displacement of the crack surface, in meters.

[0074] S3. The shale gas production prediction is obtained by solving the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 using numerical simulation methods.

[0075] S31. Set the initial values ​​of the model parameters and boundary conditions for the area to be predicted. Solve the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 using the finite element method to make a preliminary prediction of the shale gas production in the area to be predicted.

[0076] When solving the model, the boundary conditions of the model are that the boundary of the region to be analyzed is a closed non-flowing boundary with horizontal and vertical geostress; the geostress here is taken as the geostress value known in the prior art.

[0077] The initial pressures of the matrix and the gas in the fractures are considered as initial pressures, and the initial pressure of the water is calculated based on the initial saturation. The pressure at the horizontal well location in the area to be predicted is the real-time bottom hole flowing pressure measured on-site.

[0078] Based on the finite element method, and using the parameters in the matrix zone and the modified zone (including gas density, porosity, gas viscosity, aqueous viscosity, volumetric strain, gas pressure, aqueous pressure, fracture opening, matrix permeability relative to gas or aqueous phase, fracture permeability relative to gas or aqueous phase, etc.) established in the previous steps S1 and S2, the parameter values ​​at the current moment are calculated, and then the shale gas production is calculated according to the following formula.

[0079] Matrix region: (1) Within the matrix: ; ; (2) Inside the crack: ; ;

[0080] Modification area: (1) Matrix system: ; ; (2) Crack system: ; ;

[0081] The sum of the above shale gas production forecasts is taken as the total shale gas product forecast, i.e.: .

[0082] S32, based on the deviation between the preliminary prediction results of shale gas products and the fitting accuracy of historical production, the initial values ​​of the model parameters are corrected.

[0083] The initial values ​​of the modified model parameters include parameters such as the initial water saturation of the matrix zone, the initial water saturation of the modified zone, the initial opening of the hydraulic fracturing fractures, and the initial permeability of the matrix.

[0084] S33. Based on the corrected initial values ​​of model parameters and boundary conditions, the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 are solved again using the finite element method to obtain the shale gas production prediction results for the area to be predicted.

[0085] The shale gas production prediction method provided by this invention will be verified in a specific scenario below.

[0086] Hydraulic fracturing was used for shale gas extraction. The horizontal well was 610 m long and had 6 hydraulic fracturing fractures. Measured bottom-hole flowing pressure data of the shale gas well were collected at the project site and plotted as a curve as shown in Figure 3. As can be seen from the figure, the actual bottom-hole flowing pressure at the site was dynamically changing at different times, and was approximately 1.3 MPa.

[0087] For ease of calculation, the shale gas well reservoir was simplified, with fracture lengths considered to be equal and spacing considered to be uniformly distributed. In this model, roller support and no flow were used as boundary conditions. The model and boundary conditions used in the simulation are shown in Figure 4. Relevant data from the shale gas wells in the reference (Bello R, Wattenbarger R. Multi-stage Hydraulically Fractured Horizontal Shale Gas Well Rate Transient Analysis[C]. Society of Petroleum Engineers North Africa Technical Conference and Exhibition: NATCconference proceedings.: Society of Petroleum Engineers, 2010:1-18) were selected for historical production fitting. The Langmuir correlation coefficient used parameters from other reservoirs in the vicinity of the shale gas well. The calculation parameters used are shown in Table 1.

[0088] Table 1. Main parameters of numerical simulation in actual field application

[0089]

[0090] Based on the on-site measured bottom-hole flowing pressure data provided, numerical simulations were performed on the single-phase gas flow model and the gas-water two-phase flow model of this invention. The simulation results were compared with actual on-site production data, as shown in the comparison figure. Figure 5 As shown. To more accurately determine the degree of fit, the following formula is used to calculate the degree of fit: ; In the formula: The goodness of fit is represented by t, the time step for computation is d, and N is the total number of time steps for computation. The daily infiltration flow rate is obtained from numerical simulation, in m³ / d; The actual daily infiltration flow rate on site is expressed in m³ / d.

[0091] The parameters such as the initial water saturation of the matrix zone, the initial water saturation of the modified zone, the initial opening of the hydraulic fracturing fractures, and the initial permeability of the matrix in the numerical simulation process are appropriately modified to determine the parameter values ​​that best match the actual conditions of the engineering site within a reasonable range.

[0092] from Figure 5 As can be seen, the numerical simulation results are in good agreement with the actual production data on site. The numerical simulation results curves are reflected in the moments when the measured bottom hole flowing pressure changes significantly on site.

[0093] Because the time steps of the field measured data are not uniform, the field data is curve-modulated, and the daily seepage flow data is extracted according to the uniform time steps to calculate the goodness of fit between the simulation results and the actual field production data. Finally, the goodness of fit is 83.7%, which is a good fit. This shows that the model of the present invention can describe the actual shale reservoir production situation in the field well, and also shows that the data in the table are reasonable values ​​that can reflect the real situation well.

[0094] Based on the matched parameter values, the cumulative gas production of the above shale gas wells over 20 years is predicted. The bottomhole flowing pressure during the prediction period is calculated using 1.3 MPa, which is the value when the previously measured data is relatively stable. The results are as follows: Figure 6 As shown in the figure; it can be seen from the figure that the cumulative gas production over 20 years was 0.56 × 10⁻⁶. 8 m³.

[0095] Those skilled in the art will recognize that the embodiments described herein are intended to help the reader understand the principles of the invention, and should be understood that the scope of protection of the invention is not limited to such specific statements and embodiments. Those skilled in the art can make various other specific modifications and combinations based on the technical teachings disclosed in this invention without departing from the spirit of the invention, and these modifications and combinations are still within the scope of protection of this invention.

Claims

1. A method for determining the hydraulic fracturing production capacity of deep shale gas extraction, characterized in that, Includes the following steps: S1, Establish a single-phase gas flow model in the matrix zone of deep shale reservoirs considering bound water conditions; the single-phase gas flow model in the matrix zone includes a single-phase gas flow model in the matrix and a single-phase gas flow model in the fractures; S2, Establish a gas-water two-phase flow model for deep shale reservoir stimulation zones that considers fracture hydraulic coupling behavior; the gas-water two-phase flow model for the stimulation zone includes a gas-water two-phase flow model for the matrix system and a gas-water two-phase flow model for the fracture system. S3. The shale gas production is obtained by solving the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 using numerical simulation methods.

2. The method for determining the hydraulic fracturing production capacity of deep shale gas extraction according to claim 1, characterized in that, In step S1, the single-phase gas flow model within the matrix is ​​as follows: ； In the formula: The density of the gas within the matrix; The effective porosity under the condition of bound water within the matrix; The molar mass of the gas; It is the universal gas constant; For temperature; For matrix permeability; Where is the gas viscosity; g is the acceleration due to gravity; The Biot coefficient of the matrix; This refers to the gas density under standard conditions. For volumetric strain; The bulk modulus of the solid particles; This refers to the gas pressure within the matrix; The matrix density; It is the Langmuir volume constant; The Langmuir pressure constant; The single-phase gas flow model within the fracture is as follows: ； In the formula, The crack opening; This refers to the gas pressure inside the crack; The density of the gas inside the crack; denoted as , where is the crack permeability; l is the dimension along the crack length.

3. The method for determining the hydraulic fracturing production capacity of deep shale gas extraction according to claim 1, characterized in that, In step S2, the gas-water two-phase flow model of the matrix system includes a first gas phase mass balance equation and a first water phase mass balance equation; the gas-water two-phase flow model of the fracture system includes a second gas phase mass balance equation and a second water phase mass balance equation.

4. The method for determining the hydraulic fracturing production capacity of deep shale gas extraction according to claim 3, characterized in that, The first gas phase mass balance equation in the matrix system is expressed as: ； In the formula, The density of the gas phase within the matrix; This represents the saturation of the gas phase within the matrix. Porosity of the matrix; The molar mass of the gas; It is the universal gas constant; For temperature; This refers to the gas pressure within the matrix; Matrix permeability; Where is the fluid viscosity; g is the acceleration due to gravity; The Biot coefficient of the matrix; For volumetric strain; The bulk modulus of the solid particles; The matrix density; This refers to the gas density under standard conditions. It is the Langmuir volume constant; The Langmuir pressure constant; The mass balance equation for the first aqueous phase in the matrix system is expressed as: ； In the formula, The density of the aqueous phase within the matrix; This represents the saturation level of the aqueous phase within the matrix. is the compressibility coefficient of the aqueous phase; This refers to the water phase pressure within the matrix; Porosity of the matrix; Matrix permeability; The viscosity of the aqueous phase; This is the acceleration due to gravity.

5. The method for determining the hydraulic fracturing production capacity of deep shale gas extraction according to claim 3, characterized in that, The second gas phase mass balance equation in the fracture system: ； The second water phase mass balance equation in the fracture system is as follows: ； In the formula, For fluid density, It can be either gas phase (g) or aqueous phase (w); For fluid Saturation in the crack; The relative permeability of the fluid in the crack; The crack opening; The viscosity of the fluid; The average pore pressure of the fluid at the fracture surface; The dimension is along the length of the crack; For porous media relative to fluid Penetration rate; The molar mass of the gas; It is the universal gas constant; For temperature; The effective water saturation level within the fracture system; This refers to the capillary pressure within the fracture system; is the compressibility coefficient of the aqueous phase.

6. The method for determining the hydraulic fracturing production capacity of deep shale gas extraction according to claim 5, characterized in that, The effective saturation of water in a matrix system or fracture system can be expressed in the form of capillary pressure as follows: ； In the formula: The effective water saturation level within the matrix system m or the fracture system f; Capillary pressure within the matrix system or fracture system; The gas inlet pressure is z; z represents the model parameters. Here, the aqueous and gas phases also possess residual saturation, which is used to represent the saturation of the gas and aqueous phases. : ， ； ， ； In the formula, as medium Residual saturation of internal water; as medium Residual saturation of the internal gas phase; The relative permeability of the gas and aqueous phases in a two-phase flow system, whether in a matrix system or a fractured system, is expressed as follows: ； ； In the formula: The relative permeability of the gas phase within the matrix or fracture system in a two-phase flow region; , A coefficient related to porous materials; The relative permeability of the aqueous phase within the matrix or fracture system in a two-phase flow region; Z represents the effective saturation of water within the matrix or fracture system, and z′ represents the model parameters.

7. The method for determining the hydraulic fracturing production capacity of deep shale gas extraction according to claim 1, characterized in that, Step S3 includes the following sub-steps: S31. Set the initial values ​​of model parameters and boundary conditions for the area to be analyzed. Solve the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 using the finite element method. Perform a preliminary analysis of the predicted shale gas production in the area to be analyzed. S32, based on the deviation between the preliminary analysis results of shale gas products and the fitting accuracy of historical production, the initial values ​​of the model parameters are corrected; S33. Based on the corrected initial values ​​of model parameters and boundary conditions, the single-phase gas flow model in the matrix area established in step S1 and the gas-water two-phase flow model in the modified area established in step S2 are solved again using the finite element method to obtain the shale gas production analysis results of the area to be analyzed.

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