A method for calculating CO2 injection recovery and storage capacity in shale gas reservoirs based on three-pore dual-permeability

Abstract

The application discloses a kind of based on three-hole double-permeable shale gas reservoir injection CO2 and the calculation method of extraction and storage amount, belong to the unconventional natural gas reservoir development technical field.The steps S1 of the method: obtain the reservoir parameter needed for model establishment;S2: construct three-hole double-permeable physical model;S3: establish CO2-CH4 main control mechanism model;S4: coupling three-hole double-permeable physical model and establish CO2-CH4 main control mechanism model establish three-hole double-permeable flow control equation, and carry out numerical simulation, form CH4 extraction sample set and CO2 storage sample set;S5: based on CH4 extraction sample set, establish CH4 extraction calculation formula;S6: based on CO2 storage sample set, respectively establish CO2 adsorption storage capacity calculation formula and CO2 free storage capacity calculation formula, and then obtain CO2 total storage capacity.The method of the application can distinguish CO2 adsorption storage capacity and free storage capacity, and can obtain the CH4 extraction increment of relative depletion exploitation, so as to realize the quick synchronous quantitative evaluation of shale gas reservoir injection CO2 extraction effect and storage effect.

Description

Technical Field

[0001] This invention relates to the field of unconventional natural gas reservoir development technology, and in particular to a method for calculating CO2 injection and recovery volume and storage volume in shale gas reservoirs based on a three-pore dual-permeability system. Background Technology

[0002] Carbon capture, utilization, and storage (CCUS) technology is an important approach to achieving low-carbon utilization of fossil energy and geological CO2 sequestration. Injecting CO2 into shale gas reservoirs has the potential to both enhance CH4 recovery and preserve CO2. During CO2 injection into shale gas reservoirs, CH4 and CO2 undergo complex processes such as adsorption-desorption, diffusion-mass transfer, and seepage transport within organic matter, inorganic matter, and fracture systems. The extraction and preservation behaviors exhibit significant multi-media coupling characteristics. Therefore, accurately calculating the CH4 recovery and CO2 preservation rates after CO2 injection in shale gas reservoirs is crucial for evaluating the effectiveness of CO2 injection in shale gas reservoir extraction and preservation.

[0003] However, existing models mostly employ equivalent matrix models or conventional dual-medium models, typically treating organic and inorganic matter uniformly, making it difficult to accurately characterize the mass transfer processes between organic matter, inorganic matter, and fractures in real shale gas reservoirs. Furthermore, they cannot calculate the mobility of adsorbed CH4 in organic matter, free CH4 in organic matter, and free CH4 in inorganic matter / fractures after CO2 injection, leading to an overestimation of CH4 recovery. In addition, existing models insufficiently characterize the adsorption and storage of CO2 in organic matter and its free storage in the inorganic matter / fracture system, making it difficult to accurately evaluate the effective sequestration of injected CO2 in shale gas reservoirs.

[0004] Therefore, there is an urgent need for a method that can accurately calculate and evaluate the extraction rate of CH4, the amount of CO2 adsorbed and stored, and the amount of free stored CO2. Summary of the Invention

[0005] To address the problem that existing methods cannot accurately calculate CH4 extraction and CO2 effective storage, this invention provides a method for calculating CO2 extraction and storage in shale gas reservoirs based on a three-hole dual-permeability system.

[0006] The present invention provides a method for calculating CO2 injection recovery and storage capacity in shale gas reservoirs based on a three-pore dual-permeability system, comprising the following steps: S1: Based on the geological and development characteristics of the target shale gas reservoir, obtain the reservoir parameters required for model establishment.

[0007] The reservoir parameters include geometric parameters, organic matter porosity and permeability, inorganic matter porosity and permeability, fracture porosity and permeability, fracture geometric parameters, CO2 and CH4 adsorption density parameters, CO2 and CH4 diffusion parameters, stress-sensitive parameters, and fluid composition parameters.

[0008] S2: Based on three types of porous media—organic, inorganic, and fractures—an embedded discrete fracture model is used to characterize the fracture system, and a three-pore dual-permeability physical model is constructed.

[0009] Specifically, the target shale gas reservoir is divided into an organic pore system, an inorganic pore system, and a fracture system, and an embedded discrete fracture model is used to characterize the fracture system. The organic pore system, as a discontinuous reservoir medium, considers gas adsorption, desorption, and component diffusion, and exchanges with the inorganic pore system through diffusion and mass transfer. The inorganic pore system, as a continuous matrix medium, considers convection, diffusion, and stress-sensitive effects, and exchanges with the fracture system through convection and diffusion. The fracture system, as a high-permeability flow channel, considers convection and diffusion between fractures and flow from fractures to the wellbore, thus establishing a physical model of a three-pore, dual-permeability shale gas reservoir.

[0010] S3: Establish a master control mechanism model for CO2-CH4, specifically including a competitive adsorption model, a diffusion mass transfer model, and a stress-sensitive model for CO2-CH4.

[0011] The extended Langmuir model was used to characterize the competitive adsorption and desorption behavior of CO2 and CH4 in organic matter pores, resulting in a CO2-CH4 competitive adsorption model. The Fick diffusion model was used to characterize the component diffusion mass transfer process of CO2 and CH4 among organic matter, inorganic matter, and fracture systems, resulting in a diffusion mass transfer model. The Gangi model was used to characterize the dynamic changes in inorganic matter porosity and fracture permeability caused by reservoir pressure variations, resulting in a stress-sensitive model.

[0012] S4: Couple the three-pore dual-permeability physical model, CO2-CH4 competitive adsorption model, diffusion mass transfer model and stress-sensitive model to establish the CO2-CH4 flow control equations for organic pore system, inorganic pore system and fracture system, and carry out numerical simulation to obtain CH4 extraction and CO2 storage under different development regimes, forming CH4 extraction sample set and CO2 storage sample set. The CO2 storage sample set includes data on CO2 adsorption storage, CO2 free storage and total CO2 storage.

[0013] S5: Based on the CH4 recovery sample set obtained in step S4, extract the main control parameters of CH4 recovery. The main control parameters include the cumulative injected CO2 amount, CH4 geological reserves, diffusion mass transfer coefficient between organic and inorganic matter, well simmering time, characteristic diffusion length of organic matter, and injection-production pressure difference. The main control parameters are dimensionless, and the CH4 recovery variation law is described by an exponential saturation function to establish the CH4 recovery calculation formula.

[0014] S6: Based on the CO2 sequestration sample set obtained in step S4, establish calculation formulas for CO2 adsorption sequestration and CO2 free sequestration respectively. The sum of the calculated CO2 adsorption sequestration and CO2 free sequestration is the total CO2 sequestration.

[0015] For CO2 adsorption and storage capacity, the amount of CO2 adsorbed in organic matter is used as the fitting target. The cumulative injected CO2 amount, the maximum adsorption capacity of organic matter, the diffusion mass transfer coefficient between organic and inorganic matter, the well simmering time, the characteristic diffusion length of organic matter, and the competitive adsorption selectivity of CO2-CH4 are selected as the main control parameters. The main control parameters are dimensionless, and the variation law of CO2 adsorption and storage capacity is described by the exponential saturation function. The calculation formula of CO2 adsorption and storage capacity is established.

[0016] For CO2 free storage, the amount of free CO2 in the reservoir is used as the fitting target. The cumulative injected CO2 amount, the effective pore volume of the inorganic pore system and the fracture system, the CO2 density under reservoir pressure and temperature conditions, the reference pore volume, the fracture permeability and the reference permeability are selected as the main control parameters. The main control parameters are dimensionless and the variation law of CO2 free storage is described by the exponential saturation function. The formula for calculating CO2 free storage is established.

[0017] Both CH4 extraction and CO2 storage have the characteristics of "fast initial response, subsequent diminishing marginal gain, and eventually approaching the upper limit of capacity". The exponential saturation function can simultaneously satisfy this physical law, boundary conditions and fitting stability requirements. Therefore, the exponential saturation function is selected in this invention.

[0018] Compared with the prior art, the advantages of the present invention are: (1) The method of the present invention is based on the three-pore dual-permeability characteristics of organic matter, inorganic matter and fracture system of shale gas reservoir, which can characterize the occurrence and mass transfer process of CH4 and CO2 in different media respectively, avoiding the calculation deviation caused by the equivalent matrix model or conventional dual medium model that treats organic matter and inorganic matter in the same way.

[0019] (2) The present invention further fits the output results of the three-hole double-permeability model into CH4 extraction and CO2 storage calculation formulas, so that the extraction and storage can be directly calculated by development time, cumulative CO2 injection and average pressure when evaluating blocks or selecting schemes, without having to repeat the complete numerical simulation.

[0020] (3) This invention can distinguish between CO2 adsorption and storage, free storage and total storage, and can obtain the CH4 extraction increment for relative depletion mining, thereby realizing rapid and synchronous quantitative evaluation of CO2 extraction and storage effects in shale gas reservoirs, providing a basis for optimizing gas injection rate, well shut-in time, production system and huff and puff cycle.

[0021] Other advantages, objectives and features of the present invention will become apparent in part from the following description, and in part from those skilled in the art through study and practice of the invention. Attached Figure Description

[0022] Figure 1 This is a diagram of the three-pore double-permeability model established in the embodiment.

[0023] Figure 2 This is a graph showing the change in CH4 extraction rate under the CO2 injection and blotting regime in the example.

[0024] Figure 3 This is a graph showing the change in CO2 sequestration in the reservoir in the example. Detailed Implementation

[0025] The preferred embodiments of the present invention will be described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are for illustration and explanation only and are not intended to limit the present invention.

[0026] This example selects Block X of a shale gas reservoir as the target evaluation block and applies the CO2 injection and recovery rate and storage rate calculation method for shale gas reservoirs based on three-pore dual-permeability, as described in this invention. The specific steps are as follows: S1: Based on the geological and development characteristics of the target shale gas reservoir, obtain the reservoir parameters required for model establishment.

[0027] The specific reservoir parameters are as follows: model geometric length is 2000 m × 500 m × 100 m, model grid number is 100 × 10 × 5, organic matter porosity is 0.001, and organic matter permeability is 1 × 10⁻⁶. -4 mD, inorganic porosity is 0.042, inorganic permeability is 1×10 -4 The fracture porosity is 0.001 mD, the fracture permeability is 1 D, the fracture aperture is 0.0005 m, the number of fracture clusters is 90, the spacing between fracture clusters is 20 m, the fracture half-length is 100 m, the fracture height is 20 m, and the Langmuir pressure parameters for CO2 and CH4 are 1.28 × 10⁻⁶ m. 6 Pa and 3.21×10 6 The adsorption density parameters for CO2 and CH4 at Pa are 44.80 kg·m³. -3 and 40.85 kg·m -3 The diffusion parameters for CO2 and CH4 are 1.6 × 10⁻⁶. -10 m 2 ·s -1 and 0.9×10 -10 m 2 ·s -1 The rock compressibility coefficient is 5.56 × 10⁻⁶. -5 Pa-1 In the Gangi model, the critical pressure is 68.95 MPa, the stress sensitivity coefficient is 1, the maximum effective stress is 96.53 MPa, the Gangi index is 0.4, and the reference permeability is 2.09 × 10⁻⁶. -6 D, the reservoir pressure is 45 MPa, the reservoir temperature is 356 K, and the reservoir fluid is pure CH4.

[0028] S2: Constructing a physical model of a three-pore, dual-permeability shale gas reservoir; The target shale gas reservoir is represented as a combination of three types of porous media: organic pore system, inorganic pore system, and fracture system. Among them, the organic pore system is mainly used to characterize adsorbed and free gases in organic pores, the inorganic pore system is mainly used to characterize free gases in the inorganic matrix, and the fracture system is mainly used to characterize high-velocity seepage channels in hydraulic fractures and natural fractures.

[0029] The fracture system is characterized using an embedded discrete fracture model. The fractures are discretized based on the matrix mesh and the fracture network, and flow connections are established between fracture elements and their embedded matrix elements. For each matrix-fracture element pair ( m , f The transport of the fluid phase is represented by the two-point flow rate approximation (TPFA): (1) (2) In the formula, Q α m,f For α phase from matrix unit ( m ) to crack unit ( f The volumetric flow rate, m 3 ·s -1 ; T mf m represents the conductivity between the matrix and the crack. 3 ; k rα m is the relative permeability of the α phase. 2 ; m α Here is the viscosity of the α phase, Pa·s; P α m The pressure of the α phase in the matrix unit is Pa; P α f The pressure of the α phase in the fracture element is Pa; Q α f,m For α phase from crack element ( f ) to matrix unit ( mThe volumetric flow rate, m 3 ·s -1 ; T mf Defined as: (3) In the formula, k mf The pore volume weighted harmonic mean of fracture and matrix permeability, m 2 ; A mf The fluid exchange area between the matrix-crack element pair, m 2 ; <d> mf The average normal distance between the matrix and crack elements is approximated by sub-meshing the matrix elements and calculating the weighted average of the normal distances from the centroid of each matrix sub-element to the crack element, denoted as m.

[0030] For every two intersecting crack elements ( f 1, f 2) Fluid exchange is as follows: (4) (5) In the formula, Q α f1,f2 For α phase from f1 Crack unit to f2 Volumetric flow rate of the fracture element, m 3 ·s -1 ; Q α f2,f1 For α phase from f2 Crack unit to f1 Volumetric flow rate of the fracture element, m 3 ·s -1 ; T ff m is the conductivity between cracks. 3 ; P α f1 for f1 α-phase pressure in a fracture element, Pa; P α f2 for f2 Pressure of the α phase in the fracture element, Pa.

[0031] For non-intersecting crack element pairs, the transmissibility T ff It should be zero, otherwise positive. This is to determine... T ff The crack pair must be calculated ( f 1, f 2) The half-transmission rate of each crack element: (6) In the formula, For the first i The half-conductivity of a crack element, m 3 ; K fi For the first i The permeability of each fracture unit, m 2 ; a fi For the first i The aperture of each crack element, in meters; For crack elements f1 and crack unit f2 The length of the intersecting lines, in meters (m). For the first i The average normal distance from the center of each crack element segment to the intersecting line, in meters.

[0032] Each sub-segment of a crack element is located on one side of the intersection line. If the intersection line does not extend fully into the crack element, a sub-segment of the crack element can be created by pushing the intersection line outward to the edge of the crack element. T ff The harmonic mean of the two: (7) The EDFM method consists of three main steps: freeing the crack mesh based on the matrix mesh; connecting intersecting matrix-crack element pairs using Equation (3); and connecting intersecting crack-crack element pairs using Equation (7).

[0033] S3: To address the competitive adsorption of CO2-CH4, the diffusion mass transfer of components, and the stress-sensitive effect, respectively, competitive adsorption models, diffusion mass transfer models, and stress-sensitive models of CO2-CH4 were established.

[0034] The competitive adsorption and desorption behavior of CO2 and CH4 in organic matter pores was modeled using an extended Langmuir model, expressed as follows: (8) In the formula, r i for i Adsorbed gas density of the component, kg·m -3 ; for i Maximum adsorbed gas density of the component, kg·m -3 ; y i Components i The gas phase mole fraction, dimensionless; p Pressure, Pa; or for i Components or j Langmuir pressure of the component, Pa.

[0035] The diffusion behavior of CO2 and CH4 was modeled using the Fick diffusion model in porous media. i Diffusion in a single-phase fluid is represented as: (9) In the formula, J i α for α Take a look i Diffusion flux of the component, kg·m -2 ·s -1 ; Porosity is a dimensionless quantity. S α for α Phase saturation, dimensionless; t The tortuosity of the pores is dimensionless; D i α for α Take a look i The diffusion coefficient of the component, m -2 ·s -1 ; For the gradient operator, m -1 ; r α for α Phase density, kg·m -3 ; X i α for α Take a look i The mass fraction of the component, dimensionless.

[0036] The stress-sensitive mechanism is represented by the Gangi model to indicate effective permeability: (10) In the formula, K 0 represents the permeability under no confining pressure, m 2 ; s c The confining pressure is Pa; s 1 represents the maximum effective stress when the crack is completely closed, in Pa; m It is a constant, dimensionless; α B It is a constant, dimensionless; p ρ is the formation pressure, Pa.

[0037] All terms on the right side of equation (10) K (Except for 0) can be combined together and called the apparent Gangi permeability correction coefficient. This coefficient decreases as the pressure decreases and characterizes the stress-sensitive effect of the permeability of inorganic porous systems and fracture systems.

[0038] S4: Couple the three-pore dual-permeability physical model, CO2-CH4 competitive adsorption model, diffusion mass transfer model and stress-sensitive model to establish the CO2-CH4 flow control equations in the organic pore system, inorganic pore system and fracture system respectively, and carry out numerical simulation to obtain the CH4 extraction and CO2 storage under different development regimes, providing a sample set for fitting the relevant parameters of the extraction and storage calculation formulas.

[0039] The flow governing equation in the organic porous system is as follows: (11) In the formula, t For time, s; o Represents an organic matter system; has no unit. f o Organic porosity is dimensionless. α Represents the fluid phase, in which l It is a liquid phase. v It is a gas phase; i Representative components, no units; r α,o In the pores of organic matter α Phase fluid density, kg·m -3 ; S α,o In the pores of organic matter α Phase saturation, dimensionless; X i α,o In the pores of organic matter α Intraphase components i The mass fraction, dimensionless; r i ads,o Components in organic matter i The density of adsorption states, kg·m -3 ; F i D,α,o The components that are separated from organic matter by a concentration difference or chemical potential difference. i diffusion exchange term, kg·m -3 ·s -1 .

[0040] The flow governing equations in inorganic porous systems are: (12) In the formula, no Represents inorganic systems and has no units. f ino Porosity of inorganic materials is dimensionless. r α,ino In inorganic pores α Phase fluid density, kg·m -3 ; S α,ino In inorganic pores α Phase saturation, dimensionless; X i α,ino In inorganic pores α Intraphase components i The mass fraction, dimensionless; For the gradient operator, m -1 ; In inorganic pores α Chrondarcy speed, m·s -1 ; J i α,ino Components in inorganic pores i diffusion flux, kg·m -2 ·s -1 ; Q α ino,f Between inorganic matter and cracks α Phase volume exchange capacity, m 3 ·s -1 .

[0041] The flow governing equations for the fracture system are: (13) In the formula, f Represents a crack system; has no unit. w Represents the wellbore; no unit is specified. f f The crack porosity is dimensionless. r α,f For the crack α Phase fluid density, kg·m -3 ; S α,f For the crack α Phase saturation, dimensionless; X i α,f For the crack α Intraphase components i The mass fraction, dimensionless; For the crack α Chrondarcy speed, m·s -1 ; J i α,f Components in the crack i diffusion flux, kg·m -2 ·s -1 ; q α for α Phase volume flow rate, m 3 ·s -1 ; V f To control the volume of the crack, m 3 ; Q α f,ino Between the crack and the inorganic matter α Phase volume exchange capacity, m 3 ·s -1 ; Q α f,w Between the crack and the wellbore α Phase volume exchange capacity, m 3 ·s -1 .

[0042] Based on the above physical model, master control mechanism model, and flow control equations, the following is established: Figure 1 The model shown is a three-hole double-seepage model of a gas reservoir.

[0043] Numerical simulations were conducted based on the established three-pore dual-permeability model of shale gas reservoirs to obtain CH4 extraction and CO2 storage under different development regimes, providing a sample set for fitting the relevant parameters of the extraction and storage calculation formulas.

[0044] This embodiment first employs a constant bottomhole flowing pressure method to deplete production for 3 years, followed by a cyclic injection and shutdown system of "CO2 injection-well shut-in-well production," with an injection rate of 1×10⁻⁶. 5 m 3 As a baseline scheme, the injection time was 1 year, the well shut-in time was 60 days, the production time was 1 year, and there were 7 huff and puff cycles. A single-factor control method was used to set the injection rate to (0.5 × 10⁻⁶) days. 5 0.75×10 5 1.0×10 5 1.25×10 5 1.5×10 5 m 3 The simulation included five operating conditions ( / d), five operating conditions with well-closing times of 30 d, 60 d, 90 d, 120 d, and 150 d, five operating conditions with single-cycle production times of 0.5 years, 0.75 years, 1.0 year, 1.25 years, and 1.5 years, and five operating conditions with 3, 4, 5, 6, and 7 cycles of infeed / outfeed. Simultaneously, three mechanism control conditions were set up to disable CO2–CH4 competitive adsorption, component diffusion, and Gangi stress sensitivity, respectively. During the simulation, the cumulative CO2 injection amount, CO2 injection rate, cumulative and daily CH4 production, cumulative and daily CO2 production, CH4 and CO2 adsorption amounts, and the free CH4 and CO2 amounts in the organic pore system, inorganic pore system, and fracture system were recorded at each time step. Based on the state before the first gas injection, the cumulative CO2 injection volume, well shut-in time, production time, number of huff and puff cycles, cumulative CH4 recovery volume, CO2 adsorption and storage volume, and CO2 free storage volume were extracted at the end of each complete huff and puff cycle and used as a sample set for formula fitting (see Table 1 for details). This was then used for parameter fitting of the subsequent recovery and storage volume calculation formulas.

[0045] Table 1. Sample set of CH4 extraction and CO2 storage

[0046] S5: Based on the CH4 recovery sample set obtained in step S4, and considering the main controlling mechanisms of CH4 desorption, diffusion mass transfer, and pressure displacement during CO2 injection and recovery in shale gas reservoirs, the cumulative injected CO2 amount, CH4 geological reserves, diffusion mass transfer coefficient between organic and inorganic matter, well-closing time, characteristic diffusion length of organic matter, and injection-production pressure difference are selected as the main controlling parameters for CH4 recovery. Specifically, the cumulative injected CO2 amount characterizes the supply intensity of exogenous CO2; the diffusion mass transfer coefficient, well-closing time, and characteristic diffusion length of organic matter jointly characterize the extent to which CO2 enters the pores of organic matter and promotes CH4 desorption and diffusion; and the injection-production pressure difference characterizes the pressure driving force for gas migration from the matrix to fractures and the wellbore. Subsequently, the above main controlling parameters are dimensionless, and an exponential saturation function is used to describe the variation law of CH4 recovery.

[0047] The formula for calculating the cumulative extraction volume of CH4 is as follows: (14) In the formula, CH4 extraction yield, kg; CH4 geological reserves, kg; This is a correction factor for the maximum extraction rate of CH4, representing the upper limit of the extraction rate of CH4 that can be achieved within a given parameter range. It is dimensionless. The cumulative CO2 injection amount is expressed in kg. Let m be the CH4 / CO2 diffusion mass transfer coefficient between the organic and inorganic porous systems. 2 ·s -1 ; The time for simmering the well is s; The characteristic diffusion length of the organic matter porous system is given in meters (m). and a 1 represents the fitting parameter, which is dimensionless.

[0048] Based on the sample data obtained in step S4, the nonlinear least squares method is used to refine the CH4 extraction rate calculation formula. and a The parameters are fitted to minimize the error between the calculated predicted value and the CH4 extraction rate obtained from the numerical simulation, thus obtaining the parameters. The value is 0.063722, parameter a 1 is 0.77346, R 2 The final formula for calculating the CO2 huff and puff and CH4 extraction rate of shale gas reservoirs is 0.99220, and is as follows: (15) The CH4 extraction rate under the CO2 injection-puff regime under the target operating conditions can be calculated according to formula (15). The calculation results of this embodiment are shown in [reference needed]. Figure 2 .

[0049] S6: Based on the CO2 sequestration sample set obtained in step S4, extract the development time, cumulative injected CO2 amount, cumulative produced CO2 amount, CO2 adsorption amount in organic matter, free CO2 amount in inorganic pore system and fracture system, free CO2 amount in organic pores, and average reservoir pressure at each time point; then, according to the occurrence state of CO2 in shale gas reservoirs, the CO2 sequestration is divided into adsorption sequestration and free sequestration. Among them, CO2 adsorption sequestration is used to characterize the competitive adsorption and displacement sequestration of CO2 on the surface of organic pores, and CO2 free sequestration is used to characterize the free gas occurrence of CO2 in inorganic pore system, fracture system and organic pore space.

[0050] Based on this, for CO2 adsorption and storage capacity, the CO2 adsorption capacity in organic matter was used as the fitting target, and the cumulative injected CO2 amount, the maximum adsorption capacity of organic matter, the diffusion mass transfer coefficient between organic and inorganic matter, the well-closing time, the characteristic diffusion length of organic matter, and the CO2-CH4 competitive adsorption selectivity were selected as the main control parameters. Among them, the cumulative injected CO2 amount characterizes the supply level of CO2 for adsorption and storage; the diffusion mass transfer coefficient, well-closing time, and characteristic diffusion length jointly characterize the intensity of CO2 diffusion from the inorganic pore system to the organic pore system and its participation in competitive adsorption; and the CO2-CH4 competitive adsorption selectivity characterizes the preferential adsorption capacity of CO2 relative to CH4. The main control parameters were dimensionless, and an exponential saturation function was used to describe the variation law of CO2 adsorption and storage capacity, establishing a formula for calculating CO2 adsorption and storage capacity.

[0051] The formula for calculating the CO2 adsorption and storage capacity is: (16) In the formula, CO2 adsorption and sequestration capacity, kg; Maximum adsorption and storage capacity, kg; This is a dimensionless correction factor for CO2 adsorption and storage capacity. Cumulative CO2 injection volume, in kg; The maximum CO2 adsorption and storage capacity is expressed in kg. The competitive adsorption selectivity for CH4-CO2 is dimensionless. , b 1 and b 2 represents the fitting parameter, which is dimensionless.

[0052] Based on the CO2 adsorption and storage sample data obtained in step S4, the nonlinear least squares method is used to calculate the CO2 adsorption and storage capacity. The parameters b1 and b2 are fitted to minimize the error between the calculated predicted value and the CO2 adsorption and storage capacity obtained from the numerical simulation, thereby obtaining... The values ​​of b1 and b2. It is 0.78363. b 1 is 0.87407, b 2 is 0.05235, R 2 The value is 0.99151. The final formula for calculating the CO2 adsorption and storage capacity of shale gas reservoirs is as follows: (17) The CO2 adsorption and storage capacity under the target operating conditions can be calculated using formula (17).

[0053] For CO2 free storage, the amount of free CO2 in the reservoir is used as the fitting target. The cumulative injected CO2 amount, the effective pore volume of the inorganic pore system and fracture system, the CO2 density under reservoir pressure and temperature conditions, the reference pore volume, fracture permeability, and reference permeability are selected as the main control parameters. Among them, the cumulative injected CO2 amount characterizes the material supply for CO2 free storage; the effective pore volume and CO2 density characterize the spatial capacity of the reservoir to accommodate free CO2; and the fracture permeability characterizes the transport capacity of CO2 in the fracture system and its impact on the distribution of free storage. The main control parameters are dimensionless, and an exponential saturation function is used to describe the variation law of CO2 free storage, establishing a formula for calculating CO2 free storage.

[0054] The formula for calculating the amount of free CO2 stored is: (18) In the formula, CO2 free sequestration amount, kg; This is a dimensionless correction factor for the amount of free CO2 stored. The effective pore volume of inorganic porous systems and fracture systems, in m 3 ; The density of CO2 under reservoir pressure and temperature conditions, in kg·m³. -3 ; For reference pore volume, m 3 ; m is the fracture permeability. 2 ; For reference penetration rate, m 2 ; and, c 1 and c 2 represents the fitting parameter, which is dimensionless.

[0055] Based on the CO2 free storage sample data obtained in step S4, the nonlinear least squares method is used to refine the CO2 free storage calculation formula. The parameters c1 and c2 are fitted to minimize the error between the calculated predicted value and the CO2 free storage amount obtained from the numerical simulation, thereby obtaining... The values ​​of c1 and c2. It is 0.38179, a constant. c 1 is 0.160871, a constant. c 2 is 0.07351, R 2 The value is 0.99213. The final formula for calculating the CO2 throughput and free CO2 storage capacity of shale gas reservoirs is as follows: (19) The amount of free CO2 stored under the target operating conditions can be calculated using formula (19).

[0056] Total CO2 storage capacity under target operating conditions It equals the sum of the CO2 adsorption and storage capacity and the CO2 free storage capacity: (20) The CO2 adsorption and storage capacity, CO2 free storage capacity, and total CO2 storage capacity calculated in this embodiment are shown in [reference]. Figure 3 .

[0057] To verify the accuracy of the CH4 extraction and CO2 adsorption calculation formulas established in this invention, multiple sets of operating conditions with different CO2 injection rates, wellbore shut-in times, production times, and huff-and-puff cycles were set using a triple-medium numerical model. The CH4 extraction and CO2 adsorption under each operating condition were calculated using both the triple-medium numerical model and the calculation formulas of this invention, and the two calculation results were compared. The relative error calculation formula is as follows: (twenty one) (twenty two) In the formula, and The values ​​are the relative errors of CH4 extraction and CO2 adsorption, respectively, and are dimensionless. and The CH4 extraction yields, in kg, are obtained from the triple medium model and the calculation formula, respectively. and The values ​​are CO2 adsorption amounts (kg) obtained from the triple medium model and the calculation formula, respectively.

[0058] A total of 8 verification conditions were set up as shown in Table 2: Table 2, 8 sets of verification conditions

[0059] The comparison results are shown in Table 3. The calculation results of the formula are in good agreement with those of the triple medium model, and can accurately reflect the variation of CH4 extraction and CO2 adsorption under different operating conditions. The average relative error of CH4 extraction is 1.18%, and the maximum relative error is 1.29%; the average relative error of CO2 adsorption is 1.37%, and the maximum relative error is 1.58%, with errors of less than 2% for each operating condition. This indicates that the calculation formula established in this invention has high calculation accuracy and can be used to quickly predict CH4 extraction and CO2 adsorption during CO2 injection in shale gas reservoirs.

[0060] Table 3. Verification Results

[0061] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Although the present invention has been disclosed above with reference to preferred embodiments, it is not intended to limit the present invention. Any person skilled in the art can make some modifications or alterations to the above-disclosed technical content to create equivalent embodiments without departing from the scope of the present invention. Any simple modifications, equivalent changes, and alterations made to the above embodiments based on the technical essence of the present invention without departing from the scope of the present invention shall still fall within the scope of the present invention.< / d>

Claims

1. A method for calculating CO2 injection recovery and storage capacity in shale gas reservoirs based on a three-pore dual-permeability system, characterized in that... Includes the following steps: S1: Based on the geological and development characteristics of the target shale gas reservoir, obtain the reservoir parameters required for model establishment; S2: Based on three types of porous media—organic, inorganic, and fracture—an embedded discrete fracture model is used to characterize the fracture system and a three-pore dual-permeability physical model is constructed. S3: Establish a master control mechanism model for CO2-CH4, including a competitive adsorption model, a diffusion mass transfer model, and a stress-sensitive model for CO2-CH4; S4: Couple the three-pore dual-permeability physical model and the CO2-CH4 master control mechanism model to establish the CO2-CH4 flow control equations for organic pore system, inorganic pore system and fracture system, and carry out numerical simulation to obtain CH4 extraction and CO2 storage under different development regimes, forming CH4 extraction sample set and CO2 storage sample set. The CO2 storage sample set includes data on CO2 adsorption storage, CO2 free storage and total CO2 storage. S5: Based on the CH4 recovery sample set obtained in step S4, extract the main control parameters of CH4 recovery. The main control parameters include the cumulative injected CO2 amount, CH4 geological reserves, diffusion mass transfer coefficient between organic and inorganic matter, well shut-in time, characteristic diffusion length of organic matter, and injection-production pressure difference. The main control parameters are dimensionless, and the CH4 recovery variation law is described by an exponential saturation function to establish the CH4 recovery calculation formula. S6: Based on the CO2 storage sample set obtained in step S4, establish calculation formulas for CO2 adsorption storage and CO2 free storage respectively. The sum of the calculated CO2 adsorption storage and CO2 free storage is the total CO2 storage. For CO2 adsorption and storage capacity, the amount of CO2 adsorbed in organic matter is used as the fitting target. The cumulative amount of injected CO2, the maximum adsorption capacity of organic matter, the diffusion mass transfer coefficient between organic and inorganic matter, the well simmering time, the characteristic diffusion length of organic matter, and the competitive adsorption selectivity of CO2-CH4 are selected as the main control parameters. The main control parameters are dimensionless, and the variation law of CO2 adsorption and storage capacity is described by the exponential saturation function. The calculation formula of CO2 adsorption and storage capacity is established. For CO2 free storage, the amount of free CO2 in the reservoir is used as the fitting target. The cumulative injected CO2 amount, the effective pore volume of the inorganic pore system and the fracture system, the CO2 density under reservoir pressure and temperature conditions, the reference pore volume, the fracture permeability and the reference permeability are selected as the main control parameters. The main control parameters are dimensionless and the variation law of CO2 free storage is described by the exponential saturation function. The formula for calculating CO2 free storage is established.

2. The method for calculating CO2 injection recovery and storage capacity of shale gas reservoirs based on three-pore dual-permeability as described in claim 1, characterized in that, In step S5, the established formula for calculating CH4 extraction volume is as follows: In the formula, CH4 extraction yield, kg; CH4 geological reserves, kg; This is a correction factor for the maximum extraction rate of CH4, representing the upper limit of the extraction rate of CH4 that can be achieved within a given parameter range. It is dimensionless. The cumulative CO2 injection amount is expressed in kg. m is the CH4-CO2 diffusion mass transfer coefficient between the organic and inorganic porous systems. 2 ·s -1 ; The time for simmering the well is s; The characteristic diffusion length of the organic matter porous system is given in meters (m). and a 1 represents the fitting parameter, which is dimensionless.

3. The method for calculating CO2 injection recovery and storage capacity of shale gas reservoirs based on three-pore dual-permeability as described in claim 2, characterized in that, In step S5, the fitting parameters and a The method for determining 1 is as follows: Based on the CH4 extraction sample data obtained in step S4, the nonlinear least squares method is used to calculate the CH4 extraction amount in the formula. and a The parameters are fitted to minimize the error between the calculated predicted value and the CH4 extraction rate obtained from the numerical simulation, thereby obtaining... and a The possible values ​​of 1.

4. The method for calculating CO2 injection recovery and storage capacity of shale gas reservoirs based on three-pore dual-permeability as described in claim 1, characterized in that, In step S6, the formula for calculating the CO2 adsorption and storage capacity is: In the formula, CO2 adsorption and sequestration capacity, in kg; Maximum adsorption and storage capacity, kg; This is a dimensionless correction factor for CO2 adsorption and storage capacity. Cumulative CO2 injection volume, in kg; The maximum CO2 adsorption and storage capacity is expressed in kg. m is the CH4-CO2 diffusion mass transfer coefficient between the organic and inorganic porous systems. 2 ·s -1 ; The time for simmering the well is s; The characteristic diffusion length of the organic matter porous system is given in meters (m). The CH4 / CO2 competitive adsorption selectivity is dimensionless. b1 and b2 are the fitting parameters, which are dimensionless.

5. The method for calculating CO2 injection recovery and storage capacity of shale gas reservoirs based on three-pore dual-permeability as described in claim 4, characterized in that, In step S6, the fitting parameters The method for determining b1 and b2 is as follows: Based on the CO2 adsorption and storage sample data obtained in step S4, the nonlinear least squares method is used to calculate the CO2 adsorption and storage capacity using the formula. The parameters b1 and b2 are fitted to minimize the error between the calculated predicted value and the CO2 adsorption and storage capacity obtained from the numerical simulation, thereby obtaining... The values ​​of b1 and b2.

6. The method for calculating CO2 injection recovery and storage capacity of shale gas reservoirs based on three-pore dual-permeability as described in claim 1, characterized in that, In step S6, the formula for calculating the amount of free CO2 stored is: In the formula, CO2 free sequestration amount, kg; Cumulative CO2 injection volume, in kg; This is a dimensionless correction factor for the amount of free CO2 stored. The effective pore volume of inorganic porous systems and fracture systems, in m 3 ; The density of CO2 under reservoir pressure and temperature conditions, in kg·m³. -3 ; For reference pore volume, m 3 ; m is the fracture permeability. 2 ; For reference penetration rate, m 2 ; c1 and c2 are the fitting parameters, which are dimensionless.

7. The method for calculating CO2 injection recovery and storage capacity of shale gas reservoirs based on three-pore dual-permeability as described in claim 6, characterized in that, In step S6, the fitting parameters The method for determining c1 and c2 is as follows: Based on the CO2 free storage sample data obtained in step S4, the nonlinear least squares method is used to calculate the CO2 free storage amount. The parameters c1 and c2 are fitted to minimize the error between the calculated predicted value and the CO2 free storage amount obtained from the numerical simulation, thereby obtaining... The values ​​of c1 and c2.

8. The method for calculating CO2 injection recovery and storage capacity of shale gas reservoirs based on three-pore dual-permeability as described in claim 1, characterized in that, In step S1, the reservoir parameters include geometric parameters, organic matter porosity and permeability, inorganic matter porosity and permeability, fracture porosity and permeability, fracture geometric parameters, CO2 and CH4 adsorption density parameters, CO2 and CH4 diffusion parameters, stress-sensitive parameters, and fluid composition parameters.

9. The method for calculating CO2 injection recovery and storage capacity of shale gas reservoirs based on three-pore dual-permeability as described in claim 1, characterized in that, In step S3, the extended Langmuir model is used to characterize the competitive adsorption and desorption behavior of CO2 and CH4 in the pores of organic matter, and the CO2-CH4 competitive adsorption model is obtained. The Fick diffusion model was used to characterize the component diffusion mass transfer process of CO2 and CH4 among organic matter, inorganic matter and crack systems, and a diffusion mass transfer model was obtained. The Gangi model was used to characterize the dynamic changes in inorganic porosity and fracture permeability caused by reservoir pressure changes, resulting in a stress-sensitive model.

Images