Method for simulating mechanism model of CO2 huff-puff mass transfer based on numerical value

Abstract

The invention relates to the field of oil and gas fields, discloses a method for simulating a CO2 throughput mass transfer mechanism model based on numerical values, and solves the problem that the existing CO2 throughput cross-scale mass transfer mechanism is complex. According to the method, the mass transfer effect between a crack and a matrix in the CO2 huff and puff process is fully considered, a dual-medium model considering component changes is established, and a layer of crack surface is arranged on the outer surface of the model to simulate a large crack formed after volume fracturing; the method comprises the following steps: 1, establishing a shale oil horizontal well volume fracturing CO2 injection huff and puff dual-medium geologic model by using a CMG numerical simulation software GEM component model, and establishing a mechanism model according to a similarity criterion; 2, setting a fracture surface on the surface of the mechanism model according to the fracture characteristics of the horizontal well after fracturing transformation; and 3, changing model parameters, analyzing CO2 huff and puff energizing effects under different influence factors, and designing a shale oil CO2 huff and puff injection optimization scheme. The device is used for oil-gas field mass transfer research.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas field development, and in particular to a method based on a numerical simulation mechanism model of CO2 throughput mass transfer. Background Art

[0002] In recent years, as a large number of conventional oil and gas reservoirs in the world have entered the late stage of water injection development, the effect of improving recovery has been poor, and the effective development of unconventional oil reservoirs has become the focus of increasing crude oil production. Shale oil, as an important component of unconventional oil and gas reservoirs, has huge reserves worldwide. According to resource assessment data, the total reserves of shale oil resources in the world are 67840×10 8 barrels, and the technically recoverable reserves are 3362×10 8 barrels, with an average recovery rate of 4.96%. In 2009, driven by the effective development of shale oil reservoirs, the US crude oil production broke through the original downward trend and achieved its first increase. Since the 21st century, the United States has leveraged its experience in the successful development of shale gas to achieve large-scale development of Bakken, Eagle Ford and Wolf Camp shale oil. Compared with US shale oil, my country's shale oil reservoirs are mainly formed in continental sedimentary environments, which are very difficult to develop.

[0003] my country's recoverable shale oil reserves rank third in the world, with a high proportion of terrestrial origin. Resource evaluation shows that my country is in urgent need of developing shale oil. There are roughly three types of shale oil in China: terrestrial shale sandstone reservoirs, lacustrine carbonate reservoirs, and marl fracture reservoirs.

[0004] The application of huff-and-puff technology to improve oil recovery in China was relatively late due to the lack of CO2 gas sources. The first domestic field test of CO2 huff-and-puff was carried out by the East China Petroleum Bureau. In 1989, the East China Petroleum Bureau conducted a CO2 huff-and-puff test on the Su 88 well in the Zhangjiacao oilfield. The oil layer was 7.1m thick, the porosity was between 12.2% and 20.1%, the reservoir was buried at a depth of 2933.6m, the oil saturation was between 20% and 70%, the viscosity was 20mP·s, the reservoir temperature was 104℃, and the relative density of crude oil was 0.8641. The well injected a total of 116t of CO2 within 22.3h, and the well was opened for production after being shut down for 10d. The average oil production increased from 0.46t / d to 0.52t / d.

[0005] From June to November 2010, four wells in the Mabei block of Santanghu Oilfield conducted CO2 huff-and-puff tests. The crude oil density in this block is 0.884 g / cm 3 , crude oil viscosity is 104~1122mP·s, reservoir depth is 760~1580m, effective thickness is 7~13m, oil saturation is 55%~60%, reservoir temperature is 35℃~46℃. By the end of November 2010, the cumulative increase in oil production from the four huff-and-puff wells reached 144m 3Among them, the production capacity of Hu 220 well and Mabei 103 well increased from zero to an average daily oil production of 1m after the implementation of huff and puff. 3 / d, the yield-increasing effect is quite obvious.

[0006] At the end of October 2013, Liaohe Oilfield selected 10 wells in the extra-heavy oil block of Shuguang Oilfield for field testing. Currently, all wells are at the peak of cyclical oil production, with an average daily production of 6 tons per well. The average daily production of Du Well 84-37-39 is as high as 10 tons.

[0007] Shale oil is stored in the overburden matrix with a permeability of ≤0.1×10 -3 μm 2 Oil in shale sandstone, shale carbonate rock, etc. generally requires certain technical means to obtain industrial production capacity. At present, shale oil has successfully achieved breakthroughs in exploration and development in six basins such as Sichuan and Qaidam. Shale oil accumulation conditions are generally divided into source accumulation and near-source accumulation. During the accumulation process, some crude oil will migrate along natural fractures and accumulate near the source. Therefore, making full use of natural fractures for development will effectively improve the development effect. In order to obtain industrial oil flow in shale oil reservoirs, fracturing transformation must be carried out. The basic concept is to improve the seepage condition by increasing the contact area with the reservoir. Volume fracturing is an important means to transform shale oil reservoirs. By interlacing natural fractures and artificial fractures to form a fracturing transformation zone with a certain transformation volume, the permeability of the reservoir is improved. However, while volume fracturing produces a fracturing transformation zone, a complex fracture network is formed, resulting in strong multi-scale media and heterogeneity effects in the reservoir. Conventional reservoir engineering theory and numerical simulation methods cannot effectively characterize the fracture characteristics of shale reservoirs after fracturing. Therefore, it is urgent to find an advantageous fracture model to adapt to the complex fracture network of fractured shale reservoirs. At present, the commonly used fracture models for numerical simulation in academia include single medium model, dual medium model and discrete fracture model. However, these models have poor simulation effects on large-volume shale reservoirs after fracturing, and their applicability to shale reservoirs in terms of modeling is relatively poor. Summary of the invention

[0008] The patent of this invention comprehensively considers the mass transfer effect between the fractures and the matrix during the CO2 huff and puff process, and proposes a method based on the mechanism model of numerical simulation of CO2 huff and puff mass transfer, which solves the current problem of complex cross-scale mass transfer mechanism of CO2 huff and puff. A dual-medium model considering component changes was established, and a layer of fracture surface was set on the outer surface of the model to simulate the large fractures formed after volume fracturing. The specific process includes: first, using the CMG numerical simulation software GEM (component model) module to establish a dual-medium geological model for volume fracturing and CO2 injection in horizontal wells of shale oil, and establishing a mechanism model according to the similarity criterion; second, according to the fracture characteristics after the horizontal well fracturing transformation, a fracture surface is set on the surface of the mechanism model; third, the model parameters are changed to analyze the CO2 huff and puff energy enhancement effect under different influencing factors, and the shale oil CO2 injection huff and puff optimization plan is designed.

[0009] The present invention provides a method for numerically simulating a mechanism model of CO2 throughput mass transfer, the method comprising the following steps:

[0010] Step 1: Use the typical shale oil block crude oil PVT experimental data to fit the fluid state and establish a fluid model

[0011] Establish a numerical model of the reservoir, fit the array of crude oil fluid characteristics into the fluid state to form a fluid digital model, establish a component model through high-pressure physical property PVT fitting experiments, and obtain data from crude oil PVT experiments in shale oil blocks;

[0012] Step 2: Calculate the equation of state using crude oil PVT property data

[0013] After fitting the data of crude oil PVT experiment to the PVT physical property data of crude oil, the state equation is calculated using the PVT physical property data of crude oil to determine the fluid PVT properties; the fluid PVT properties include: crude oil density, crude oil saturation pressure, crude oil viscosity, crude oil relative volume and minimum miscibility pressure;

[0014] Step 3: Establish a shale oil corner point network geological model

[0015] The basic parameters of the shale oil geological model actually measured are input into the Petrel RE module of the three-dimensional geological model Petrel software, and the shale oil corner grid geological model is established according to the grid scale; the three-layer porosity distribution field map is generated by using the interlayer porosity heterogeneity processing method and the three-layer network porosity component generation method, and the generated three-layer porosity distribution field map is integrated into a typical porosity model;

[0016] Step 4: Establish a dual-medium geological model for horizontal well volume fracturing in shale oil reservoirs and a shale oil CO2 injection huff-and-puff mechanism model

[0017] The shale oil corner network geological model is imported into the CMG component module to generate a dual-medium geological model for volume fracturing of horizontal wells in shale reservoirs. Based on the production mode of horizontal wells in shale reservoirs, the dual-medium geological model is numerically simulated with historical data of CO2 huff-and-puff production, and the oil production, water production and formation pressure are fitted to obtain the simulation values ​​of production dynamic parameters. According to the actual oil production, water production and formation pressure changes of the reservoir, the porosity, permeability and oil-water two-phase permeability curves are adjusted to obtain the fitted dual-medium geological model. The cube characteristic unit body with a side length less than the minimum side length of the dual-medium geological model is extracted from the fitted dual-medium geological model, and a fracture surface is set on the surface of the characteristic unit body to form a shale oil CO2 injection huff-and-puff mechanism model.

[0018] Step 5: Optimize the shale oil CO2 injection huff and puff scheme based on the shale CO2 injection huff and puff mechanism model

[0019] According to the CO2 injection and huff-and-puff mechanism model of shale oil, boundary conditions, well-sucking time and injection-production system are selected as influencing factors of CO2 huff-and-puff; in the boundary condition study, the mechanism model fracture surface is set to be single-sided open, double-sided open, four-sided open and six-sided open; and on the basis of the boundary condition study, a fracture surface model with three sides open in different situations is set; the recovery rate under different boundary conditions is analyzed; in the well-sucking time study, different well-sucking times are selected, and the recovery rate under different well-sucking times is analyzed; in the injection-production system study, the CO2 injection pressure is set to be constant pressure injection, step-by-step pressure increase and step-by-step pressure reduction; the recovery rate under different injection-production systems is analyzed; the recovery rate parameters of CO2 huff-and-puff mass transfer under different influencing factors are obtained, and the boundary conditions, well-sucking time and injection-production system corresponding to the maximum recovery rate are selected.

[0020] Preferably, the state equation calculated using the fitted fluid PVT data in step 2 is the UNCONG state equation; the UNCONG state equation is a three-parameter cubic state equation, which has a general expression as shown in formula (1):

[0021] Z 3 +sZ 2 +qZ+r=0 (1)

[0022] Where: Z represents the compressibility factor of the fluid, s, q, and r represent the three parameters of the cubic state equation respectively; the three parameters are determined by the following formula:

[0023]

[0024] In formula (2), w and u are general coefficients; A and B are coefficients related to the mixing state and are determined by formula (3):

[0025]

[0026] Since the three-parameter cubic state equation needs to calculate the compressibility factor of the mixture, a and b need to be determined by the mixing rule. The linear mixing rule is usually used. Under the linear mixing rule, a and b can be determined by formula 4. For the mixture system, if it contains N c The molar fractions of the i-th and j-th components in the mixture are x i , x j , the interaction coefficient between components i and j is k i,j ;

[0027]

[0028] Among them, x i , x j are the mole fractions of the i-th and j-th components in the mixture, respectively, and k i,j N c The interaction coefficient between components i and j.

[0029] Preferably, establishing the shale oil corner point network geological model in step 3 further includes the following steps:

[0030] Step 301 collects data required for modeling, including layer data, well logging data, and core test data;

[0031] Step 302: using the Petrel RE module in the Petrel software to establish a shale oil corner point grid model;

[0032] In step 303, based on the experience of establishing the shale oil corner point network geological model, the step lengths of the grid model in the X and Y directions are both selected to be 20 m.

[0033] Preferably, the basic parameters of the shale oil geological model in step 3 include reservoir size, reservoir depth, reservoir pressure, mean matrix permeability, mean matrix porosity, main fracture permeability, main fracture porosity, main fracture aperture, and main fracture half-length; the method for processing the interlayer porosity heterogeneity is to use three levels with inconsistent attribute distributions, and the corresponding three-layer grid porosity field generation method is to apply different random seed numbers for Gaussian discretization and adjust the offset; the generated three-layer porosity distribution field map is integrated to form a typical porosity model.

[0034] Preferably, step 4 of establishing a shale oil CO2 injection mechanism model specifically includes the following steps:

[0035] Step 401: Import the geological model established by the Petrel software into the CMG numerical simulation component model to establish a shale oil reservoir horizontal well volume fracturing dual-medium geological model; the seepage equation based on it is as shown in formula (5), and the oil and gas phase material balance equation based on it is as shown in formula (6);

[0036]

[0037] Where k is the permeability, unit: mD; ρ w , o , g They are water phase density, oil phase density and gas phase density, in g / cm 3 ;μ w , μ o , μ g They are water phase viscosity, oil phase viscosity and gas phase viscosity, unit: mP·s; x i is the molar fraction of component i, unit: mol; Φ is the phase field variable, dimensionless; F is the interfacial energy, unit: J / m 3 ; is the porosity, q is the flow rate, unit: m 3 / s; t is time, unit: s;

[0038]

[0039] Among them, z i is the total mole fraction, unit: mol; L is the liquid phase mole fraction, unit: mol; V is the gas phase mole fraction, unit: mol;

[0040] Step 402 of fitting oil production, water production and formation pressure is based on the horizontal well production mode of the shale oil reservoir, and numerical simulation of CO2 huff-and-puff production history data is performed on the geological model to fit oil production, water production and formation pressure to obtain simulation values ​​of production dynamic parameters; according to the actual oil production, water production and formation pressure changes of the oil reservoir, the porosity, permeability and oil-water two-phase permeability curve are adjusted to fit the daily oil production, daily water production and formation pressure;

[0041] Step 403 extracts characteristic units and establishes a shale oil CO2 injection huff-and-puff mechanism model; extracts a cubic characteristic unit from the dual-medium geological model, encrypts the unit grid, sets fracture surfaces on the six faces of the unit, and when the fracture surface permeability is set to a threshold of 100 mD, the fracture surface is considered open, and when the fracture surface permeability is set to 0.05 mD, the fracture surface is considered closed.

[0042] Preferably, the parameter adjustment principle of the fitting standard determined by fitting the daily oil production, daily water production and formation pressure is as follows:

[0043] (7) Porosity

[0044] According to the basic characteristics of the reservoir, it is known that the physical properties of shale reservoirs are mainly low porosity and low permeability, with an average porosity of 11.8%. The porosity has a certain range of variation, and the allowable range of variation is between ±5%.

[0045] (8) Permeability

[0046] The permeability of shale oil reservoirs is between 0.1 and 0.01 mD. Considering the measurement error and the uncertainty of well distribution, the adjustment range of permeability is enlarged or reduced by 2-5 times.

[0047] (9) Rock fluid compressibility

[0048] Fluid compressibility is laboratory determined and is considered a definite parameter;

[0049] (10) Initial fluid saturation and initial pressure

[0050] The parameters determined during reservoir geological modeling are usually considered as definitive parameters, with minor modifications allowed when necessary;

[0051] (11) Relative permeability curve

[0052] Since the grid of the reservoir simulation model is relatively fine and there is serious heterogeneity inside the grid, the relative permeability curve is regarded as an uncertain parameter. During the fitting process, the permeability curve is adjusted based on experience;

[0053] (12)PVT high-voltage properties

[0054] The PVT high-pressure physical properties of oil and water are measured through indoor tests and have been fitted by a numerical simulation phase simulator and are considered to be definite parameters.

[0055] Preferably, the recovery factor parameters of CO2 injection and mass transfer under different influencing factors in step 5 are obtained, and the optimal soaking time and injection-production scheme refer to obtaining the maximum recovery factor by studying the following three aspects. The specific steps are as follows:

[0056] Step 501: Study the recovery factor under different boundary conditions

[0057] The fracture surface is set on the surface of the mechanism model, and the model is divided into four forms: single-sided opening, double-sided opening, four-sided opening and six-sided opening. The mechanism model can intuitively reflect the communication relationship between fractures and fractures, and between fractures and matrix. Different opening surfaces can simulate the degree of fracture development in the reservoir after large-volume fracturing. The mechanism model has a shorter calculation time. The CO2 injection and injection mass transfer laws under different boundary conditions are analyzed, and the boundary conditions corresponding to the maximum recovery rate of the oil well are regarded as the optimal boundary conditions.

[0058] Step 502: Study the recovery rate under different well soaking time

[0059] Combining the actual situation of the mine with the experience of previous research, the optimal soaking time is 5 days, 10 days, 15 days and 20 days for simulation; the CO2 injection and mass transfer law under different soaking times is analyzed, and the soaking time corresponding to the maximum recovery rate of the oil well is regarded as the optimal soaking time;

[0060] Step 503: Study the recovery rate under different injection and production conditions

[0061] The injection-production conditions are divided into constant pressure injection, step-by-step pressure injection and step-by-step pressure reduction injection; among them, constant pressure injection means that the injection pressure rises to 1.25 times of the formation pressure each time, the step-by-step pressure increases are 1.0, 1.1, 1.2, 1.3, 1.4 and 1.5 times of the formation pressure respectively; the step-by-step pressure reductions are 1.5, 1.4, 1.3, 1.2, 1.1 and 1.0 times of the formation pressure respectively; the CO2 throughput mass transfer laws under different injection-production systems are analyzed, and the injection-production scheme corresponding to the maximum recovery rate of the oil well is regarded as the optimal injection-production scheme.

[0062] The present invention proposes a method based on numerical simulation of the mechanism model of CO2 huff and puff mass transfer, which solves the current problem of complex cross-scale mass transfer mechanism of CO2 huff and puff; the present invention fully considers the mass transfer effect between fractures and matrix during CO2 huff and puff, establishes a dual medium model that considers component changes, and sets a layer of fracture surface on the outer surface of the model to simulate the large fractures formed after volume fracturing. The specific process includes: first, using the CMG numerical simulation software GEM (component model) module to establish a dual medium geological model of shale oil horizontal well volume fracturing and CO2 injection, and establish a mechanism model according to the similarity criterion; second, according to the fracture characteristics after the horizontal well fracturing transformation, a fracture surface is set on the surface of the mechanism model; third, the model parameters are changed to analyze the CO2 huff and puff energy enhancement effect under different influencing factors, and the shale oil CO2 injection huff and puff optimization plan is designed. BRIEF DESCRIPTION OF THE DRAWINGS

[0063] Figure 1 It is a flow chart of a method based on a mechanism model of numerical simulation of CO2 throughput mass transfer;

[0064] Figure 2 It is a technical route schematic diagram of a method embodiment based on a mechanism model of numerical simulation of CO2 throughput mass transfer;

[0065] Figure 3 It is a method based on the mechanism model of numerical simulation of CO2 throughput and mass transfer. Schematic diagram of the model with different situations opened on three sides;

[0066] Figure 4 It is a method based on the mechanism model of numerical simulation of CO2 huff-and-puff mass transfer. The recovery factor curves under different boundary conditions;

[0067] Figure 5It is a method based on the mechanism model of numerical simulation of CO2 huff-and-puff mass transfer. The oil recovery factor diagram under three-sided opening in different situations;

[0068] Figure 6 It is a method based on numerical simulation of the mechanism model of CO2 huff-and-puff mass transfer. The oil recovery factor curves under different well soaking times are shown;

[0069] Figure 7 It is a method based on the numerical simulation of the mechanism model of CO2 injection and mass transfer. The crude oil recovery factor curve under different injection and production systems. DETAILED DESCRIPTION

[0070] Here, exemplary embodiments will be described in detail, and examples thereof are shown in the accompanying drawings. When the following description refers to the drawings, unless otherwise indicated, the same numbers in different drawings represent the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with the present invention.

[0071] The embodiment of the present invention provides a mechanism model method based on numerical simulation of CO2 throughput mass transfer, such as Figure 1 As shown, the method comprises the following steps:

[0072] Step 1: Use the typical shale oil block crude oil PVT experimental data to fit the fluid state and establish a fluid model

[0073] Establish a numerical model of the reservoir, fit the array of crude oil fluid characteristics into the fluid state to form a fluid digital model, establish a component model through high-pressure physical property PVT fitting experiments, and obtain data from crude oil PVT experiments in shale oil blocks;

[0074] Step 2: Calculate the equation of state using crude oil PVT property data

[0075] After fitting the data of crude oil PVT experiment to the PVT physical property data of crude oil, the state equation is calculated using the PVT physical property data of crude oil to determine the fluid PVT properties; the fluid PVT properties include: crude oil density, crude oil saturation pressure, crude oil viscosity, crude oil relative volume and minimum miscibility pressure;

[0076] Step 3: Establish a shale oil corner point network geological model

[0077] The basic parameters of the shale oil geological model actually measured are input into the Petrel RE module of the three-dimensional geological model Petrel software, and the shale oil corner grid geological model is established according to the grid scale; the three-layer porosity distribution field map is generated by using the interlayer porosity heterogeneity processing method and the three-layer network porosity component generation method, and the generated three-layer porosity distribution field map is integrated into a typical porosity model;

[0078] Step 4: Establish a dual-medium geological model for horizontal well volume fracturing in shale oil reservoirs and a shale oil CO2 injection huff-and-puff mechanism model

[0079] The shale oil corner network geological model is imported into the CMG component module to generate a dual-medium geological model for volume fracturing of horizontal wells in shale reservoirs. Based on the production mode of horizontal wells in shale reservoirs, the dual-medium geological model is numerically simulated with historical data of CO2 huff-and-puff production, and the oil production, water production and formation pressure are fitted to obtain the simulation values ​​of production dynamic parameters. According to the actual oil production, water production and formation pressure changes of the reservoir, the porosity, permeability and oil-water two-phase permeability curves are adjusted to obtain the fitted dual-medium geological model. A cube characteristic unit with a side length of 1.04 m is extracted from the fitted dual-medium geological model, and a fracture surface is set on the surface of the characteristic unit to form a shale oil CO2 injection huff-and-puff mechanism model.

[0080] Step 5: Optimize the shale oil CO2 injection huff and puff scheme based on the shale CO2 injection huff and puff mechanism model

[0081] According to the CO2 injection huff-and-puff mechanism model of shale oil, boundary conditions, well shut-in time and injection-production system were selected as the influencing factors of CO2 huff-and-puff. In the boundary condition study, the fracture surface of the mechanism model was set to open on one side, two sides, four sides and six sides. On the basis of the boundary condition study, the fracture surface model with three sides opened in different situations was set. The recovery rate under different boundary conditions was analyzed. In the well shut-in time study, different well shut-in times (5, 10, 15 and 20 days) were selected to analyze the recovery rate under different well shut-in times. In the injection-production system study, CO2 was set to open on one side, two sides, four sides and six sides. 2 The injection pressure includes constant pressure injection, step-by-step pressure increase and step-by-step pressure reduction; (wherein, constant pressure injection means that the injection pressure rises to 1.25 times of the formation pressure each time, the step-by-step pressure increase is 1.0, 1.1, 1.2, 1.3, 1.4 and 1.5 times of the formation pressure respectively; the step-by-step pressure reduction is 1.5, 1.4, 1.3, 1.2, 1.1 and 1.0 times of the formation pressure respectively) analyze the recovery factor under different injection-production systems; obtain the recovery factor parameters of CO2 throughput mass transfer under different influencing factors, and select the boundary conditions, soaking time and injection-production system corresponding to the maximum recovery factor.

[0082] In one embodiment, the UNCONG state equation is a three-parameter cubic state equation, having a general expression as shown in equation (1):

[0083] Z 3 +sZ 2 +qZ+r=0 (1)

[0084] Where: Z represents the compressibility factor of the fluid, s, q, and r represent the three parameters of the cubic state equation respectively; the three parameters are determined by formula (2):

[0085]

[0086] In formula (2), w and u are general coefficients; A and B are coefficients related to the mixing state and are determined by formula (3):

[0087]

[0088] Since the three-parameter cubic state equation needs to calculate the compressibility factor of the mixture, a and b need to be determined by the mixing rule. The linear mixing rule is usually used. Under the linear mixing rule, a and b can be determined by formula 4. For the mixture system, if it contains N c The molar fractions of the i-th and j-th components in the mixture are x i , x j , the interaction coefficient between components i and j is k i,j ;

[0089]

[0090] Among them, x i , x j are the mole fractions of the i-th and j-th components in the mixture, respectively, and k i,j N c The interaction coefficient between components i and j.

[0091] In one embodiment, establishing the shale oil corner point network geological model in step 3 further includes the following steps:

[0092] Step 301 collects data required for modeling, including layer data, well logging data, and core test data;

[0093] Step 302: using the Petrel RE module in the Petrel software to establish a shale oil corner point grid model;

[0094] In step 303, based on the experience of establishing the shale oil corner point network geological model, the step lengths of the grid model in the X and Y directions are both selected to be 20 m.

[0095] Preferably, the basic parameters of the shale oil geological model in step 3 include reservoir size, reservoir depth, reservoir pressure, mean matrix permeability, mean matrix porosity, main fracture permeability, main fracture porosity, main fracture aperture, and main fracture half-length; the method for processing the interlayer porosity heterogeneity is to use three levels with inconsistent attribute distributions, and the corresponding three-layer grid porosity field generation method is to apply different random seed numbers for Gaussian discretization and adjust the offset; the generated three-layer porosity distribution field map is integrated to form a typical porosity model.

[0096] In one embodiment, step 4 of establishing a shale oil CO2 injection mechanism model specifically includes the following steps:

[0097] Step 401: Import the geological model established by the Petrel software into the CMG numerical simulation component model to establish a shale oil reservoir horizontal well volume fracturing dual-medium geological model; the seepage equation based on it is as shown in formula (5), and the oil and gas phase material balance equation based on it is as shown in formula (6);

[0098]

[0099] Where k is the permeability, unit: mD; ρ w , o , g They are water phase density, oil phase density and gas phase density, in g / cm 3 ;μ w , μ o , μ g They are water phase viscosity, oil phase viscosity and gas phase viscosity, unit: mP·s; x i is the molar fraction of component i, unit: mol; Φ is the phase field variable, dimensionless; F is the interfacial energy, unit: J / m 3 ; is the porosity, q is the flow rate, unit: m 3 / s; t is time, unit: s;

[0100]

[0101] Among them, z i is the total mole fraction, unit: mol; L is the liquid phase mole fraction, unit: mol; V is the gas phase mole fraction, unit: mol;

[0102] Step 402 of fitting oil production, water production and formation pressure is based on the horizontal well production mode of the shale oil reservoir, and numerical simulation of CO2 huff-and-puff production history data is performed on the geological model to fit oil production, water production and formation pressure to obtain simulation values ​​of production dynamic parameters; according to the actual oil production, water production and formation pressure changes of the oil reservoir, the porosity, permeability and oil-water two-phase permeability curve are adjusted to fit the daily oil production, daily water production and formation pressure;

[0103] Step 403 extracts characteristic units and establishes a shale oil CO2 injection huff-and-puff mechanism model; extracts a cube characteristic unit whose side length is less than the minimum side length of the dual medium geological model in the dual medium geological model, encrypts the unit grid, sets fracture surfaces on the six faces of the unit, and when the fracture surface permeability is set to the threshold value of 100mD, the fracture surface is considered to be open, and when the fracture surface permeability is set to 0.05mD, the fracture surface is considered to be closed.

[0104] In one embodiment, the parameter adjustment principle of the fitting standard determined by fitting the daily oil production, the daily water production and the formation pressure is as follows:

[0105] (13) Porosity

[0106] According to the basic characteristics of the reservoir, it is known that the physical properties of shale reservoirs are mainly low porosity and low permeability, with an average porosity of 11.8%. The porosity has a certain range of variation, and the allowable range of variation is between ±5%.

[0107] (14) Permeability

[0108] The permeability of shale reservoirs is between 0.1 and 0.01 mD. Considering the measurement error and the uncertainty of well distribution, the adjustment range of permeability is enlarged or reduced by 2-5 times.

[0109] (15) Rock fluid compressibility

[0110] Fluid compressibility is laboratory determined and is considered a definite parameter;

[0111] (16) Initial fluid saturation and initial pressure

[0112] The parameters determined during reservoir geological modeling are usually considered as definitive parameters, with minor modifications allowed when necessary;

[0113] (17) Relative permeability curve

[0114] Since the grid of the reservoir simulation model is relatively fine and there is serious heterogeneity inside the grid, the relative permeability curve is regarded as an uncertain parameter. During the fitting process, the permeability curve is adjusted based on experience;

[0115] (18)PVT high pressure properties

[0116] The PVT high-pressure physical properties of oil and water are measured through indoor tests and have been fitted by a numerical simulation phase simulator and are considered to be definite parameters.

[0117] In one embodiment, obtaining the recovery factor parameters of CO2 injection and mass transfer under different influencing factors in step 5, and optimizing the well-keeping time and injection-production scheme refers to obtaining the maximum recovery factor by studying the following three aspects, and the specific steps are as follows:

[0118] The boundary condition corresponding to the maximum oil well recovery factor is regarded as the optimal boundary condition;

[0119] Step 502: Study the recovery rate under different well soaking time

[0120] Combining the actual situation of the mine with the experience of previous research, the soaking time of 5 days, 10 days, 15 days and 20 days was selected for simulation; the CO2 injection and mass transfer law under different soaking times was analyzed, and the soaking time corresponding to the maximum recovery rate of the oil well was regarded as the optimal soaking time;

[0121] Step 503: Study the recovery rate under different injection and production conditions

[0122] The injection-production conditions are divided into constant pressure injection, step-by-step pressure injection and step-by-step pressure reduction injection; among them, constant pressure injection means that the injection pressure rises to 1.25 times of the formation pressure each time, the step-by-step pressure increases are 1.0, 1.1, 1.2, 1.3, 1.4 and 1.5 times of the formation pressure respectively; the step-by-step pressure reductions are 1.5, 1.4, 1.3, 1.2, 1.1 and 1.0 times of the formation pressure respectively; the CO2 throughput mass transfer laws under different injection-production systems are analyzed, and the injection-production scheme corresponding to the maximum recovery rate of the oil well is regarded as the optimal injection-production scheme.

[0123] The present invention proposes a method based on numerical simulation of the mechanism model of CO2 huff and puff mass transfer, which solves the current problem of complex cross-scale mass transfer mechanism of CO2 huff and puff; the present invention fully considers the mass transfer effect between fractures and matrix during CO2 huff and puff, establishes a dual medium model that considers component changes, and sets a layer of fracture surface on the outer surface of the model to simulate the large fractures formed after volume fracturing. The specific process includes: first, using the CMG numerical simulation software GEM (component model) module to establish a dual medium geological model of shale oil horizontal well volume fracturing and CO2 injection, and establish a mechanism model according to the similarity criterion; second, according to the fracture characteristics after the horizontal well fracturing transformation, a fracture surface is set on the surface of the mechanism model; third, the model parameters are changed to analyze the CO2 huff and puff energy enhancement effect under different influencing factors, and the shale oil CO2 injection huff and puff optimization plan is designed.

[0124] Embodiment 1

[0125] The technical solution of the present invention is further described in detail below in conjunction with the embodiments, but the protection scope of the present invention is not limited thereto. Figure 2 As shown;

[0126] In one embodiment, the basic data of this model is selected from a typical shale reservoir. On the basis of the dual medium model, a fracture surface is set to simulate the fracture network after volume fracturing.

[0127] Based on the understanding of fluid characteristics, geological properties and fluid-solid coupling in shale reservoirs, a numerical model of CO2 huff-and-puff components in horizontal wells in shale reservoirs is established.

[0128] (I) Use the PVT experimental data of crude oil in typical shale oil blocks to fit the fluid state and establish a fluid model; (PVT fitting of shale oil reservoir fluid)

[0129] To establish a numerical model of the reservoir, it is necessary to first establish a numerical model of the fluid. To accurately digitize the fluid characteristics, it is necessary to fit the fluid state. In terms of digitizing fluid characteristics, unlike the black oil model, the core method of simulating and restoring fluid characteristics in the component model is the state equation. The premise for the realization of the state equation is that the high-pressure physical property PVT fitting experiment needs to be consistent with the physical model experiment. Therefore, the PVT numerical simulation fitting experiment is an indispensable prerequisite step for establishing the component model. The three-parameter cubic state equation based on the model is shown in formula (1);

[0130] The physical property parameters of the model crude oil are derived from the data obtained from the PVT experiment of crude oil in a shale oil block of a domestic oil field. In order to restore the fluid state of the formation crude oil, the experimental crude oil sample is obtained by mixing ground degassed crude oil with flash steam using a dissolved gas-oil ratio of 20. The detailed data of the pseudo-components are shown in Table 1.

[0131] Table 1 Physical properties of model crude oil pseudo-components

[0132]

[0133] From the data in Table 1, it can be seen that the oil sample has a large content of heavy components and a low content of methane relative to C9 and above. Therefore, this oil sample belongs to medium-high viscosity crude oil. The laboratory measured the crude oil viscosity data under the formation state (formation temperature 89.28℃, formation pressure 35.25MPa) to be about 15-20mPa·s. The CO2 immersion experiment shows that the CO2 viscosity reduction effect of this oil sample is strong and the miscibility effect is good.

[0134] (II) Using crude oil PVT physical property data to calculate the equation of state

[0135] After fitting the PVT physical property data of crude oil, the degree of restoration of the fluid's formation state is high, which can express the high-pressure physical properties and seepage state of the crude oil fluid to a certain extent. Among them, the oil layer fluid: oil, natural gas and formation water stored underground.

[0136] High-pressure physical properties: the physical properties of oil and gas reservoir fluids under high pressure and high temperature underground;

[0137] Seepage refers to the flow of fluid in porous media. Materials composed of granular or fragmented materials and containing many pores or cracks are called porous media. Usually, seepage in soil or rock below the surface is called groundwater movement, which is the most common seepage phenomenon in nature. Seepage has a wide range of applications in water conservancy, geology, mining, petroleum, environmental protection, chemical industry, biology, medicine and other fields.

[0138] The state equation is calculated using this set of fitted fluid PVT data. The UNCONG state equation is solved using the PR equation or the SRK equation, both of which are cubic state equations based on three parameters and have a general expression as shown in equation (1).

[0139] Z 3 +sZ 2 +qZ+r=0 (1)

[0140] Where Z is the compressibility factor of the fluid; s, q, r are three parameters, determined by the following formula:

[0141]

[0142] A and B in Formula 2 are coefficients related to the mixing state and are determined by Formula (3):

[0143]

[0144] Since the three-parameter cubic state equation needs to calculate the compressibility factor of the mixture, a and b need to be determined by the mixing rule. There are many kinds of mixing rules, and the linear mixing rule is usually used. Under the linear mixing rule, a and b can be determined by formula 4. For a mixture system, if it contains N c The molar fractions of the i-th and j-th components in the mixture are x i , x j , the interaction coefficient between components i and j is k i,j ,but:

[0145]

[0146] The fluid PVT properties calculated by the fitted state equation can be regarded as the PVT properties of the actual fluid flowing in the formation, so as to establish a fluid model for application on the carrier of the geological model. After the fluid PVT properties are determined, they can generally be applied to most geological models. However, the less the fluid model matches the geological model, the shorter the convergence time, and the lower the degree of conformity between the results calculated by the model in the later stage of production and the actual situation.

[0147] (III) Establishing shale oil corner point network geological model using Petrel software

[0148] The development of natural fractures is a typical geological feature of shale reservoir development. Its influence on permeability anisotropy and local seepage conditions is particularly important. The effect on the entire reservoir is the heterogeneity of porosity and permeability field maps. First, the data required for modeling (layer data, logging data, core test data, etc.) are collected. The basic parameters of the model are shown in Table 2. Then, the Petrel RE module in the Petrel software is used to establish a corner grid model with a grid scale of 51×100×1.5km. On the basis of ensuring the accuracy of describing geological conditions, combined with the experience of geological model establishment, the step length of the X and Y directions of the grid model is selected as 20m. The method for dealing with interlayer porosity heterogeneity is to use three layers with inconsistent attribute distribution. The corresponding porosity field generation method of the three-layer grid is to use different random seed numbers for Gaussian discretization and adjust the offset. The generated three-layer porosity distribution field map is integrated to form a typical porosity model.

[0149] (iv) importing the model into CMG numerical simulation software, and using the CEM module of CMG numerical simulation software to establish a dual-medium geological model for volume fracturing of horizontal wells in shale oil reservoirs;

[0150] The shale oil corner network geological model was imported into the CMG numerical simulation software, and the dual-medium geological model of horizontal well volume fracturing in shale reservoirs was established using the component module of the CMG numerical simulation software. The CMG component model is a type of reservoir simulation software that can be used to evaluate the development and production effects of reservoirs. The model has multiple sub-models that can simulate the generation, movement and discharge of multiple fluid components in the reservoir, as well as the interaction and influence between fluids and rocks. It is a more comprehensive reservoir model.

[0151] The seepage equation on which the model is based is shown in formula (5), and the oil and gas phase material balance equation on which it is based is shown in formula (6). The basic parameters of the shale oil corner network geological model are shown in Table 2.

[0152]

[0153] Where k is the permeability, mD, ρ w , o , g Respectively, the water phase density, oil phase density and gas phase density, g / cm 3 , μ w , μ o , μ g are respectively the viscosity of water phase, oil phase and gas phase, mP·s, x i is the mole fraction of component i, mol, Φ is the phase field variable, dimensionless, and F is the interfacial energy, J / m 3 , is the porosity, q is the flow rate, m 3 / s, t is time, s.

[0154]

[0155] Among them, z i is the total mole fraction, mol, L is the liquid phase mole fraction, mol, and V is the gas phase mole fraction, mol.

[0156] Table 2 Basic parameters of shale oil geological model

[0157]

[0158] Table 3 Basic parameters of shale oil mechanism model

[0159]

[0160] (V) Fitting of oil production, water production and formation pressure

[0161] Based on the horizontal well production mode of the shale oil reservoir, the geological model is numerically simulated with historical data of CO2 huff-and-puff production to fit oil production, water production and formation pressure; the simulation values ​​of production dynamic parameters are obtained; according to the actual oil production, water production and formation pressure changes of the reservoir, the porosity, permeability and oil-water two-phase permeability curves are adjusted. Fit the daily oil production, daily water production and formation pressure. Historical fitting is the process of inversely calculating and correcting the physical parameters of the oil layer based on the actual dynamic parameters observed. This inversion process often has multiple solutions, that is, the combination of multiple physical parameters can obtain the same result. Therefore, it is necessary to determine the fitting standard to standardize the solution process of the inversion calculation. There is currently no universal method for historical fitting. Through the understanding and summary of shale oil reservoirs and geological laws, the parameter adjustment principles for determining the fitting standard are as follows:

[0162] (19) Porosity

[0163] According to the basic characteristics of the reservoir described in the reservoir description, it can be known that the physical properties of shale reservoirs are generally poor, mainly low porosity and low permeability, with an average porosity of 11.8%. Therefore, the porosity has a certain range of variation, and the allowable change range is between ±5%.

[0164] (20) Permeability

[0165] The permeability of shale oil reservoirs is generally very small, and the permeability variation range is large. Taking into account uncertain factors such as measurement errors and well distribution, the adjustment range of permeability is relatively large, which can be enlarged or reduced by 2-5 times.

[0166] (21) Rock fluid compressibility

[0167] The compression coefficient of liquid is measured in the laboratory and has a very small range of variation. It should be regarded as a definite parameter. The compression coefficient of rock is affected by the internal saturated liquid and stress state, and has a certain range of variation. In addition, the non-effective part connected to the effective thickness also has certain porosity, which plays a certain elastic role in the ascent process. Taking this part of the influence into account, the rock compression coefficient is allowed to be expanded by 1-1.5 times.

[0168] (22) Initial fluid saturation and initial pressure

[0169] These parameters are those determined during reservoir geological modeling and should normally be considered as definitive, with small modifications allowed when necessary.

[0170] (23) Relative permeability curve

[0171] Since the grid of the reservoir simulation model is fine and there is serious heterogeneity inside the grid, its influence cannot be ignored. Therefore, the relative permeability curve should be regarded as an uncertain parameter. During the fitting process, appropriate adjustment of the relative permeability curve is allowed.

[0172] (24)PVT high pressure properties

[0173] The PVT high-pressure physical properties of oil and water are measured through indoor tests and have been fitted by a numerical simulation phase simulator. The variation range is very small and should be regarded as definite parameters.

[0174] (VI) Establishing a model for the mechanism of CO2 injection into shale oil

[0175] The characteristic unit cell is extracted from the fitted geological model, and the mechanism model is established according to the similarity criterion. A 1.04×1.04×1.04m cube characteristic unit cell is extracted from the geological model, and the unit cell grid is encrypted. A fracture surface with a thickness of 0.02m is set on the six faces of the unit cell. When the fracture surface permeability is set to 100mD, the fracture surface is considered to be open, and when the fracture surface permeability is set to 0.05mD, the fracture surface is considered to be closed. After the model is established, a constant pressure production method is adopted, and the formation fluid pressure is set to 35MPa. The CO2 injection pressure is 1.25 times the formation pressure. The initial settings of the mechanism model are opening the six sides of the fracture, 6 times of huff and puff, constant pressure injection, and well shut-in for 10 days.

[0176] (VII) Establishing models with different boundary conditions

[0177] Since the fracture characteristics of horizontal wells after fracturing are that the fractures themselves are long and wide, with strong conductivity, and the fractures and matrix, as well as the fractures and fractures are intertwined like a grid, fracture surfaces are set on the surface of the mechanism model, and the model is divided into four forms: single-sided opening, double-sided opening, four-sided opening, and six-sided opening. This mechanism model can intuitively reflect the communication relationship between fractures and fractures, and between fractures and matrix. Different opening surfaces can simulate the degree of fracture development in the reservoir after large-volume fracturing. The mechanism model is also simpler in calculation, which greatly reduces the calculation time. The CO2 throughput mass transfer law under different boundary conditions was analyzed. The results show that with the increase of the opening surface, the recovery rate also increases ( Figure 4 , Table 4).

[0178] Table 4 Recovery factor data under different boundary conditions

[0179]

[0180] This is because increasing the open surface is conducive to the mass transfer of CO2 between the fracture and the matrix, and the contact between CO2 and crude oil is more complete, which is more conducive to dissolving crude oil, reducing interfacial tension, and extracting light components of crude oil;

[0181] In the three-sided opening model study, due to the different positions of the opening surfaces, Figure 3 As shown, case 1: the top, bottom, and side surfaces are open; case 2: the top and two non-adjacent side surfaces are open; case 3: the top and two adjacent side surfaces are open. The recovery rates are also different ( Figure 5 , Table 5), which indicates that CO2 flooding also plays a role in the CO2 injection process.

[0182] Table 5 Oil recovery data under three-side opening in different situations

[0183]

[0184] (VIII) Establish a CO2 throughput model under different soaking times (5 days, 10 days, 15 days and 20 days), and analyze the CO2 throughput mass transfer law under different soaking times. A soaking time that is too short is not conducive to the full contact between CO2 and crude oil, while a soaking time that is too long is not conducive to the production efficiency of the oil well, and too long a soaking time may cause CO2 to diffuse into deeper formations, which is not conducive to maintaining reservoir pressure. Combining the actual situation of the mine with the experience of previous research, the soaking time of 5 days, 10 days, 15 days and 20 days is selected for simulation. The results show that as the soaking time increases, the contact time between CO2 and crude oil during the soaking process is longer, and the recovery rate also increases accordingly ( Figure 6 , Table 6).

[0185] Table 6 Crude oil recovery data at different soaking times

[0186]

[0187] (IX) Establish CO2 throughput models under different injection and production systems (constant pressure injection, step-by-step pressure increase and step-by-step pressure reduction) and analyze the CO2 throughput and mass transfer laws under different injection and production systems. Among them, constant pressure injection means that the injection pressure rises to 1.25 times the formation pressure each time, and the step-by-step pressure increase is 1.0, 1.1, 1.2, 1.3, 1.4, and 1.5 times the formation pressure respectively; the step-by-step pressure reduction is 1.5, 1.4, 1.3, 1.2, 1.1, and 1.0 times the formation pressure respectively. The results show that the recovery rate is higher under the step-by-step pressure increase working system ( Figure 7 , Table 7), this is because in the middle and late stages of the round, the formation pressure is insufficient and needs to be supplemented.

[0188] Table 7 Crude oil recovery data under different injection and production systems

[0189]

[0190]

[0191] (10) Based on the above research results, optimize the CO2 injection and puff scheme for shale oil.

[0192] The above studies show that as the number of opening faces increases, the recovery rate also increases; as the well soaking time increases, the recovery rate also increases; the recovery rate is higher under the step-by-step pressure increase working system. Based on the comprehensive consideration of the actual geological characteristics of the reservoir and the reservoir economy, the final preferred working system is six-face opening, 15-day well soaking and step-by-step pressure increase.

[0193] (X) Study on the CO2 throughput and mass transfer law of the mechanism model

[0194] Boundary conditions, well soaking time and injection-production system are selected as influencing factors of CO2 huff and puff. Boundary conditions, well soaking time and injection-production system are selected as influencing factors of CO2 huff and puff. When studying the mass transfer law of CO2 huff and puff under different boundary conditions, the mechanism model fracture surface is set to open on one side, two sides, four sides and six sides, and the final recovery rate, the content of light components extracted by CO2, the pressure field change, the CO2 injection amount and the CO2 injection layer are analyzed. The study shows that the more open surfaces there are, the more fully CO2 is mixed with crude oil, the more obvious the effect of CO2 extraction of light components is, and the higher the recovery rate is. In addition, in the three-side opening model, due to the different positional relationship between the opening surface and the huff and puff well, the recovery rate is slightly different, which shows that CO2 also has the role of CO2 displacement in the huff and puff process; when studying the mass transfer law of CO2 huff and puff under different well soaking times, the characteristic unit well soaking time t is calculated according to the similarity criterion to correspond to (5, 10, 15, 20 days). Studies have shown that the longer the soaking time, the more complete the contact between CO2 and crude oil, the more light components of crude oil can be extracted, and the greater the recovery rate; when studying the CO2 throughput mass transfer law under different injection-production systems, the injection-production system is divided into constant pressure injection (each time raised to 1.25 times the formation pressure), step-by-step pressure increase (1.0, 1.1, 1.2, 1.3, 1.4, 1.5) and step-by-step pressure reduction (1.5, 1.4, 1.3, 1.2, 1.1, 1.0).

[0195] According to the model results, in different boundary condition models, Figure 4 As shown in Figure 2, as the number of open faces increases, the recovery rate also increases. This is because the more fracture faces are opened, the more favorable it is for the diffusion of CO2, making the contact between CO2 and crude oil more complete, and the recovery rate is improved. In the model with three faces open, Figure 5 As shown in Figure 2, the recovery factor varies due to the different positions of the opening surface, which indicates that CO2 flooding also exists in the CO2 huff-and-puff process; in the models with different well-keeping times, Figure 6 As shown in Figure 2, as the soaking time increases, CO2 has a longer contact time with crude oil during the soaking process, and the recovery rate increases accordingly. Figure 7 As shown in the figure, the recovery rate is higher under the step-by-step pressure-raising system. This is because in the middle and late stages of the round, the formation pressure is insufficient and needs to be supplemented. Based on the comprehensive consideration of the actual geological characteristics of the reservoir and the reservoir economy, the six-side opening, 15-day well soaking and step-by-step pressure-raising system is finally selected.

[0196] The embodiment of the present invention provides a method for a mechanism model based on numerical simulation of CO2 huff and puff mass transfer, which solves the problem of the complex cross-scale mass transfer mechanism of CO2 huff and puff at present; based on the seepage characteristics and geological characteristics of typical shale oil areas, the present invention establishes a large-scale geological model of horizontal well volume fracturing in oil reservoirs, and performs historical fitting on the production data of the mine. On this basis, characteristic units are extracted, and based on the fluid exchange characteristics of the fracture system and the matrix system of the dual medium model in the numerical simulation software, the large fractures formed after the horizontal well volume fracturing are combined to establish a study on the mass transfer law of shale oil injection CO2 huff and puff fracture-matrix. This method reveals the CO2 diffusion law, mass transfer mechanism and energy-enhancing effect under different conditions, and can provide theoretical guidance for improving the technical strategy of CO2 huff and puff, thereby realizing the efficient development of shale oil injection CO2 huff and puff. At present, there is no mechanism model of the cross-scale mass transfer mechanism of CO2 huff and puff in the field of oil and gas field development technology.

Claims

1. A method based on numerical simulation of the mechanism model of CO2 throughput mass transfer, characterized in that: The method comprises the following steps: Step 1: Use the typical shale oil block crude oil PVT experimental data to fit the fluid state and establish a fluid model Establish a numerical model of the reservoir, fit the array of crude oil fluid characteristics into the fluid state to form a fluid digital model, establish a component model through high-pressure physical property PVT fitting experiments, and obtain data from crude oil PVT experiments in shale oil blocks; Step 2: Calculate the equation of state using crude oil PVT property data After fitting the data of crude oil PVT experiment to the PVT physical property data of crude oil, the state equation is calculated using the PVT physical property data of crude oil to determine the fluid PVT properties; the fluid PVT properties include: crude oil density, crude oil saturation pressure, crude oil viscosity, crude oil relative volume and minimum miscibility pressure; Step 3: Establish a shale oil corner point network geological model The basic parameters of the shale oil geological model actually measured are input into the Petrel RE module of the three-dimensional geological model Petrel software, and the shale oil corner grid geological model is established according to the grid scale; the three-layer porosity distribution field map is generated by using the interlayer porosity heterogeneity processing method and the three-layer network porosity component generation method, and the generated three-layer porosity distribution field map is integrated into a typical porosity model; Step 4: Establish a dual-medium geological model for volume fracturing of horizontal wells in shale oil reservoirs and a shale oil CO2 injection huff-and-puff mechanism model. Import the shale oil corner network geological model into the CMG component module to generate a dual-medium geological model for volume fracturing of horizontal wells in shale oil reservoirs. Based on the production mode of horizontal wells in shale oil reservoirs, perform numerical simulation of CO2 huff-and-puff production historical data on the dual-medium geological model, fit oil production, water production and formation pressure, and obtain simulation values ​​of production dynamic parameters. According to the actual oil production, water production and formation pressure changes of the reservoir, the porosity, permeability and oil-water two-phase permeability curves are adjusted to obtain the fitted dual-medium geological model. A cube characteristic unit body with a side length less than the minimum side length of the dual-medium geological model is extracted from the fitted dual-medium geological model, and a fracture surface is set on the surface of the characteristic unit body to form a shale oil CO2 injection huff-and-puff mechanism model. Step 5: Optimize the shale oil CO2 injection huff and puff scheme based on the shale CO2 injection huff and puff mechanism model According to the CO2 injection and huff-and-puff mechanism model of shale oil, boundary conditions, well-sucking time and injection-production system are selected as influencing factors of CO2 huff-and-puff; in the boundary condition study, the mechanism model fracture surface is set to be single-sided open, double-sided open, four-sided open and six-sided open; and on the basis of the boundary condition study, a fracture surface model with three sides open in different situations is set; the recovery rate under different boundary conditions is analyzed; in the well-sucking time study, different well-sucking times are selected, and the recovery rate under different well-sucking times is analyzed; in the injection-production system study, the CO2 injection pressure is set to constant pressure injection, step-by-step pressure increase and step-by-step pressure reduction; the recovery rate under different injection-production systems is analyzed, and the recovery rate parameters of CO2 huff-and-puff mass transfer under different influencing factors are obtained, and the boundary conditions, well-sucking time and injection-production system corresponding to the maximum recovery rate are selected.

2. The method according to claim 1, characterized in that: The state equation calculated by using the fitted fluid PVT data in step 2 is the UNCONG state equation; the UNCONG state equation is a three-parameter cubic state equation, which has a general expression as shown in formula (1): With 3 +sZ 2 +qZ+r=0 (1) Where: Z represents the compressibility factor of the fluid, s, q, and r represent the three parameters of the cubic state equation respectively; the three parameters are determined by formula (2): In formula (2), w and u are coefficients; A and B are coefficients related to the mixing state and are determined by formula (3): Since the three-parameter cubic state equation needs to calculate the compressibility factor of the mixture, a and b need to be determined by the mixing rule. The linear mixing rule is usually used. Under the linear mixing rule, a and b can be determined by formula (4). For a mixture system, if it contains N c The molar fractions of the i-th and j-th components in the mixture are x i , x j , the interaction coefficient between components i and j is k i,j ; Among them, x i , x j are the mole fractions of the i-th and j-th components in the mixture, respectively, and k i,j N c The interaction coefficient between components i and j.

3. The method according to claim 1, characterized in that: The establishment of the shale oil corner point network geological model in step 3 also includes the following steps: Step 301 collects data required for modeling, including layer data, well logging data, and core test data; Step 302: using the Petrel RE module in the Petrel software to establish a shale oil corner point grid model; In step 303, based on the experience of establishing the shale oil corner point network geological model, the step lengths of the grid model in the X and Y directions are both selected to be 20 m.

4. The method according to claim 1, characterized in that: The basic parameters of the shale oil geological model in step 3 include reservoir size, reservoir depth, reservoir pressure, mean matrix permeability, mean matrix porosity, main fracture permeability, main fracture porosity, main fracture aperture, and main fracture half-length; The method for dealing with interlayer porosity heterogeneity is to use three levels with inconsistent attribute distribution. The corresponding three-layer grid porosity field generation method is to apply different random seed numbers for Gaussian discretization and adjust the offset; the generated three-layer porosity distribution field map is integrated to form a typical porosity model.

5. The method according to claim 1, characterized in that: Step 4: Establishing the shale oil CO2 injection mechanism model specifically includes the following steps: Step 401: Import the geological model established by the Petrel software into the CMG numerical simulation component model to establish a shale oil reservoir horizontal well volume fracturing dual-medium geological model; the seepage equation based on it is as shown in formula (5), and the oil and gas phase material balance equation based on it is as shown in formula (6); Where k is the permeability, unit: mD; ρ w , o , g They are water phase density, oil phase density and gas phase density, in g / cm 3 ;μ w , μ o , μ g They are water phase viscosity, oil phase viscosity and gas phase viscosity, unit: mP·s; x i is the molar fraction of component i, unit: mol; Φ is the phase field variable, dimensionless; F is the interfacial energy, unit: J / m 3 ; is the porosity, q is the flow rate, unit: m 3 / s; t is time, unit: s; Among them, z i is the total mole fraction, unit: mol; L is the liquid phase mole fraction, unit: mol; V is the gas phase mole fraction, unit: mol; Step 402 of fitting oil production, water production and formation pressure is based on the horizontal well production mode of the shale oil reservoir, and numerical simulation of CO2 huff-and-puff production history data is performed on the geological model to fit oil production, water production and formation pressure to obtain simulation values ​​of production dynamic parameters; according to the actual oil production, water production and formation pressure changes of the oil reservoir, the porosity, permeability and oil-water two-phase permeability curve are adjusted to fit the daily oil production, daily water production and formation pressure; Step 403 extracts characteristic units and establishes a shale oil CO2 injection huff-and-puff mechanism model; extracts a cube characteristic unit whose side length is less than the minimum side length of the dual medium geological model in the dual medium geological model, encrypts the unit grid, sets fracture surfaces on the six faces of the unit, and when the fracture surface permeability is set to the threshold value of 100mD, the fracture surface is considered to be open, and when the fracture surface permeability is set to 0.05mD, the fracture surface is considered to be closed.

6. The method according to claim 5, characterized in that: The parameter adjustment principles for fitting the daily oil production, daily water production and formation pressure to determine the fitting standard are as follows: (1) Porosity According to the basic characteristics of the reservoir, it is known that the physical properties of shale reservoirs are mainly low porosity and low permeability, with an average porosity of 11.8%. The porosity has a certain range of variation, and the allowable range of variation is between ±5%. (2) Permeability The permeability of shale oil reservoirs is between 0.1 and 0.01 mD. Considering the measurement error and the uncertainty of well distribution, the adjustment range of permeability is enlarged or reduced by 2-5 times. (3) Rock fluid compressibility Fluid compressibility is laboratory determined and is considered a definite parameter; (4) Initial fluid saturation and initial pressure The parameters determined during reservoir geological modeling are usually considered as definitive parameters, with minor modifications allowed when necessary; (5) Relative permeability curve Since the grid of the reservoir simulation model is relatively fine and there is serious heterogeneity inside the grid, the relative permeability curve is regarded as an uncertain parameter. During the fitting process, the permeability curve is adjusted based on experience; (6)PVT high-voltage properties The PVT high-pressure physical properties of oil and water are measured through indoor tests and have been fitted by a numerical simulation phase simulator and are considered to be definite parameters.

7. The method according to claim 1, characterized in that: The recovery factor parameters of CO2 injection and mass transfer under different influencing factors are obtained in step 5. The boundary conditions, well soaking time and injection-production system corresponding to the maximum recovery factor of the oil well are selected, which means obtaining the maximum recovery factor by studying the following three aspects. The specific steps are as follows: Step 501: Study the recovery factor under different boundary conditions The fracture surface is set on the surface of the mechanism model, and the model is divided into four forms: single-sided opening, double-sided opening, four-sided opening and six-sided opening. The mechanism model can intuitively reflect the communication relationship between fractures and fractures, and between fractures and matrix. Different opening surfaces can simulate the degree of fracture development in the reservoir after large-volume fracturing. The mechanism model has a shorter calculation time. The CO2 injection and injection mass transfer laws under different boundary conditions are analyzed, and the boundary conditions corresponding to the maximum recovery rate of the oil well are regarded as the optimal boundary conditions. Step 502: Study the recovery rate under different well soaking time Combining the actual situation of the mine with the experience of previous research, the soaking time of 5 days, 10 days, 15 days and 20 days was selected for simulation; the CO2 injection and mass transfer law under different soaking times was analyzed, and the soaking time corresponding to the maximum recovery rate of the oil well was regarded as the optimal soaking time; Step 503: Study the recovery rate under different injection and production conditions The injection-production conditions are divided into constant pressure injection, step-by-step pressure injection and step-by-step pressure reduction injection; among them, constant pressure injection means that the injection pressure rises to 1.25 times of the formation pressure each time, the step-by-step pressure increases are 1.0, 1.1, 1.2, 1.3, 1.4 and 1.5 times of the formation pressure respectively; the step-by-step pressure reductions are 1.5, 1.4, 1.3, 1.2, 1.1 and 1.0 times of the formation pressure respectively; the CO2 throughput mass transfer laws under different injection-production systems are analyzed, and the injection-production scheme corresponding to the maximum recovery rate of the oil well is regarded as the optimal injection-production scheme.

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