Carbonate rock porosity measurement plate construction method

Abstract

The invention relates to a carbonate rock porosity measurement plate construction method, which comprises the following steps of: setting pore structure parameters of different reservoir types according to core test data, and establishing a calculation formula between porosity and longitudinal wave velocity under different reservoir type conditions by utilizing an Xu-Payne rock physical model; the activation function is adopted to unify the porosity measurement plates of different reservoir types into a set of formulas, and then the high-precision porosity measurement plate suitable for the carbonate rock stratum is established. The obtained pore measurement plate can reflect the influence of various pore structures in the carbonate rock, adjacent well logging information does not need to be introduced, and then the precision of the pore measurement plate of the carbonate rock stratum is improved.

Description

Technical Field

[0001] The present invention belongs to the field of oil and gas exploration and development, and particularly relates to a method for constructing a carbonate pore measurement template based on a rock physics model and an activation function. Background Art

[0002] Accurate construction of a pore measurement template is of great significance for calculating oil and gas reserves. Conventional methods for constructing a pore measurement template mainly use well logging data to directly establish a fitting relationship between wave impedance and porosity. The main steps include: 1. Collect well logging longitudinal wave impedance and porosity data within the target interval of the work area; 2. If the number of data points in the work area is small, supplement the longitudinal wave impedance and porosity data from well logging data with similar geological conditions in adjacent work areas; 3. Through regression fitting, obtain the conversion relationship between longitudinal wave impedance and porosity, and then construct the pore measurement template.

[0003] Applying the existing technology to carbonate formations will result in the following problems: 1. Since multiple pore structures coexist within carbonate rocks, different pore structures correspond to different wave impedance-porosity relationships. The existing pore measurement template construction technology is difficult to depict the influence of different pore structures on the pore measurement template, thereby reducing the accuracy of the pore measurement template; 2. Since fractures and caves are relatively developed in carbonate formations, well logging blanking and loss phenomena often occur when drilling through fracture and cave locations, resulting in the lack of well logging data on wave impedance and porosity. The existing technology requires a large number of data points to calculate a stable regression relationship when constructing a pore measurement template. For the stability of the calculation process, the existing technology often needs to introduce well logging data from adjacent areas to supplement the number of sample points. However, the reservoir conditions and fluid properties in different work areas often vary greatly, which will have an obvious adverse impact on the construction accuracy of the pore measurement template. The existing technology is difficult to overcome the above defects, thereby significantly reducing the accuracy of the constructed pore measurement template. Summary of the Invention

[0004] In order to solve the above technical problems, the present invention provides a method for constructing a carbonate pore measurement template.

[0005] The technical solution of the present invention is as follows:

[0006] A method for constructing a carbonate pore measurement template, characterized by comprising the following steps:

[0007] 1) Collect well logging data and reservoir condition parameters within the work area;

[0008] 2) Collect laboratory test data of core and fluid properties, including rock porosity measurements, rock longitudinal wave impedance measurements, rock mineral modulus, three pore geometric aspect ratio data of rock, rock mineral density, formation water salinity, API gravity, gas-oil ratio, and gas gravity, where the three pore structures of the rock are "fracture-type" pores, "pore-type" pores, and "cavity-type" pores.

[0009] 3) Set the proportion of the three pore structures in the fracture-type reservoir and the cavity-type reservoir. The fracture-type reservoir is a reservoir type with a relatively high proportion of "fracture-type" pores, and the cavity-type reservoir is a reservoir type with a relatively high proportion of "pore-type" and "cavity-type" pores.

[0010] 4) Set the distribution range of porosity in the pore template.

[0011] 5) Set the water saturation data of the rock in the pore template.

[0012] 6) Substitute the data collected in steps 1) and 2), the proportion data of the three pore structures set in step 3), the porosity distribution range set in step 4), and the water saturation data set in step 5) into the Xu-Payne rock physics model, and calculate the longitudinal wave impedance of the fracture-type reservoir and the cavity-type reservoir changing with the porosity data respectively.

[0013] 7) Take the longitudinal wave impedance as the abscissa and the porosity as the ordinate, and draw the longitudinal wave impedance-porosity relationship diagrams of the fracture-type reservoir and the cavity-type reservoir respectively. Project the porosity and longitudinal wave impedance sample points measured from the core onto the diagrams. If there are obvious differences between the calculated longitudinal wave impedance-porosity curve and the sample points measured from the core, return to step 3 and readjust the proportion values of the three pores in the fracture-type reservoir or the cavity-type reservoir until the trend of the calculated longitudinal wave impedance-porosity curve becomes consistent with that of the sample points measured from the core.

[0014] 8) Take the porosity as the independent variable and the calculated longitudinal wave impedance as the dependent variable, and conduct regression analysis to establish the fitting formulas of the longitudinal wave impedance-porosity corresponding to the fracture-type reservoir and the cavity-type reservoir respectively.

[0015] 9) Select the sigmoid activation function as the weight function, and use the activation function to unify the regression formulas of the fracture-type reservoir and the cavity-type reservoir into one formula. The activation function formula is: f(x) = 1 / (1 + e^(-x)).

[0016] 10) Output the formula obtained in step 9), and this formula is the constructed carbonate rock pore template.

[0017] Preferably, in step 1), collect logging mineral content data, formation pressure data, and formation temperature data.

[0018] Preferably, step 6) specifically includes:

[0019] ① Substitute the mineral content and mineral modulus data of the carbonate rock into the Voigt-Reuss-Hill formula to calculate the bulk modulus and shear modulus of the rock skeleton of the mineral mixture;

[0020] ② Use the pore structure proportion data and porosity data to calculate the porosity of each of the three pore structures;

[0021] ③ Substitute the rock skeleton modulus of the mineral mixture, porosity data, and pore geometric aspect ratio data into the differential equivalent medium approximation model to calculate the dry rock modulus varying with porosity;

[0022] ④ Substitute the formation temperature, formation pressure, formation water salinity, gas-oil ratio, API gravity, and gas gravity data into the Bazlte-Wang formula to calculate the fluid property data under reservoir conditions;

[0023] ⑤ Substitute the fluid property data under reservoir conditions, water saturation data, and dry rock modulus data into the Gassmann fluid substitution formula to calculate the bulk modulus of the rock under the condition of rock saturated with fluid;

[0024] ⑥ Substitute the rock mineral content, mineral density, porosity, and water saturation data into the density volume average equation to calculate the density of the rock when saturated with fluid;

[0025] ⑦ Use the bulk modulus of the rock when saturated with fluid and the density when saturated with fluid to calculate the P-wave velocity of the rock when saturated with fluid;

[0026] ⑧ Use the P-wave velocity and density of the rock when saturated with fluid to calculate the P-wave impedance data of the rock when saturated with fluid.

[0027] Further preferably, in step ①, the Voigt-Reuss-Hill formula is:

[0028]

[0029]

[0030]

[0031] where M vrh is the equivalent mixture modulus, N is the number of mineral components of the rock, f i is the content of rock mineral i, and M i is the bulk modulus or shear modulus of rock mineral i.

[0032] Further preferably, in step ②, the formula is:

[0033]

[0034] Among them, when i takes values from 1 to 3, are the porosities of "seam type", "hole type" and "cavity type" pores respectively, F i are the proportions of "seam type", "hole type" and "cavity type" pores respectively, is the porosity.

[0035] Further preferably, in step ③, the differential equivalent medium approximation model formula is:

[0036]

[0037]

[0038] Among them, when i takes values from 1 to 3, K0 is the bulk modulus of the rock skeleton, μ0 is the shear modulus of the rock skeleton, K1 is the bulk modulus of the dry rock after adding "seam type" pores, μ1 is the shear modulus of the dry rock after adding "seam type" pores, K2 is the bulk modulus of the dry rock after adding "seam type" and "hole type" pores, μ2 is the shear modulus of the dry rock after adding "seam type" and "hole type" pores, K3 is the bulk modulus of the dry rock after adding "seam type", "hole type" and "cavity type" pores, μ3 is the shear modulus of the dry rock after adding "seam type", "hole type" and "cavity type" pores, are the porosities of "seam type", "hole type" and "cavity type" pores respectively, P i and Q i are the geometric factors of "seam type", "hole type" and "cavity type" respectively. When the geometric aspect ratio of the pores is a fixed value, P i and Q i are constants.

[0039] Further preferably, in step ④, the calculation formula for the crude oil velocity in the Bazlte-Wang formula is:

[0040]

[0041] Among them, V oil is the crude oil velocity, T is the formation temperature, P is the formation pressure, ρ * is the pseudo-density of the gas-bearing crude oil. The calculation formula of ρ * is:

[0042]

[0043]

[0044]

[0045] Among them, ρ0 For API gravity, G is the gas gravity, and R G is the gas-oil ratio;

[0046] The calculation formula for the crude oil density in the Bazlte-Wang formula is:

[0047]

[0048] The calculation formula for the formation water velocity under reservoir conditions in the Bazlte-Wang formula is:

[0049] V b = V q + S(1170 - 9.6T + 0.055T 2 - 0.000085T 3 + 2.6P - 0.0029TP - 0.0476P 2 + S 1.5 (780 - 10P + 0.16P 2 ) - 1820S 2 )

[0050] where S is the formation water salinity determined in the laboratory, and V w is the pure water velocity;

[0051] The calculation formula for the formation water density in the Bazlte-Wang formula is:

[0052] ρ b = ρ w + S{0.668 + 0.44S + 10 -6 [300P - 2400PS + T(80 + 3T - 3300S - 13P + 47PS)}

[0053] where ρ w is the pure water density.

[0054] Further preferably, in step ⑤, the Gassmann fluid substitution formula is:

[0055]

[0056] where K sat is the rock bulk modulus when the rock is saturated with fluid; is the porosity; K d is the bulk modulus of the dry rock; K m is the bulk modulus of the rock skeleton; K f is the effective bulk modulus of the oil-water mixed fluid under reservoir conditions, and the calculation formula for K f is:

[0057]

[0058] Among them, S w is the water saturation, K b is the bulk modulus of formation water, K oil is the bulk modulus of oil:

[0059]

[0060]

[0061] Further preferably, in step ⑥, the density body average equation is:

[0062]

[0063] Among them, ρ m is the rock matrix density, and the calculation formula is:

[0064]

[0065] Among them, N is the number of mineral components of the rock, f i is the content of rock mineral i, ρ i is the density of rock mineral i.

[0066] Further preferably, in step ⑦, the calculation formula for the P-wave velocity is:

[0067] In step ⑧, the calculation formula for the P-wave impedance is: Zp = V sat ρ sat .

[0068] The beneficial technical effects of the present invention are as follows:

[0069] A method for constructing a porosity measurement template applicable to carbonate rock formations according to the present invention sets the pore structure parameters of different reservoir types according to core test data, uses the Xu-Payne rock physics model to establish a calculation formula between porosity and P-wave velocity under different reservoir type conditions, and uses an activation function to unify the porosity measurement templates of different reservoir types into a set of formulas, thereby establishing a high-precision porosity measurement template applicable to carbonate rock formations. Through the application of rock physics modeling and regression functions, the constructed porosity measurement template can reflect the influence of various pore structures inside the carbonate rock, and there is no need to introduce well logging data from adjacent areas, thereby improving the accuracy of the porosity measurement template for carbonate rock formations.

[0070] The porosity measurement template constructed by the present invention can avoid the calculation errors caused by missing data points in the prior art and overcome the calculation errors caused by pore structure differences in the prior art, thereby improving the construction accuracy of the porosity measurement template for carbonate rock formations. Description of the Drawings

[0071] Figure 1 This is the flow chart for constructing the carbonate rock pore measurement version of the present invention.

[0072] Figure 2 It is a comparison of the longitudinal wave impedance-porosity relationship diagram corresponding to the vuggy reservoir and the longitudinal wave impedance-porosity relationship diagram corresponding to the fractured reservoir with the projection of the longitudinal wave impedance-porosity sample points of core testing.

[0073] Figure 3 This is a schematic diagram of the activation function.

[0074] Figure 4 It is a comparison of the longitudinal wave impedance-pore measurement version and the projection of the longitudinal wave impedance-porosity sample points of core testing. Detailed implementation manners

[0075] The present invention will be further described in detail below in conjunction with specific embodiments.

[0076] Embodiment

[0077] This embodiment includes the following steps, as shown in Figure 1 :

[0078] 1) Collect well logging data and reservoir condition parameters in the work area, including well logging mineral content data, formation pressure data, and formation temperature data. In this embodiment, the calcite content is 95%, the dolomite content is 1%, the clay mineral content is 4%, the formation pressure is 85 Mpa, and the formation temperature is 160 degrees Celsius.

[0079] 2) Collect laboratory test data on core and fluid properties, including rock porosity measurement values, rock longitudinal wave impedance measurement values, rock mineral moduli, three rock pore geometric aspect ratios, rock mineral densities, formation water salinity, API gravity, gas-oil ratio, and gas gravity, where the three pore structures of the rock are "fracture-type" pores, "pore-type" pores, and "vug-type" pores. In this embodiment, the calcite bulk modulus is 71 GPa, the calcite shear modulus is 30 GPa, and the calcite density is 2.73 g / cm 3 , the dolomite bulk modulus is 80.2 GPa, the dolomite shear modulus is 48.8 GPa, and the dolomite mineral density is 2.87 g / cm 3 , the clay mineral modulus is 31 GPa, the clay mineral shear modulus is 13 GPa, and the clay mineral density is 2.58 g / cm 3 , the formation water salinity is 0.08 kg / L, the API gravity is 30, the gas-oil ratio is 50, the gas gravity is 0.6, the aspect ratio of the "fracture-type" pores is 0.01, the aspect ratio of the "pore-type" pores is 0.2, and the aspect ratio of the "vug-type" pores is 0.8.

[0080] 3) Set the proportion of the three pore structures in the fractured reservoir and the vuggy reservoir, where the fractured reservoir is a reservoir type with a relatively high proportion of "fracture-type" pores, and the vuggy reservoir is a reservoir type with relatively high proportions of "pore-type" and "cavity-type" pores. In this embodiment, the proportion of "fracture-type" pores in the fractured reservoir is 0.2, the proportion of "pore-type" pores is 0.7, and the proportion of "cavity-type" pores is 0.1. The proportion of "fracture-type" pores in the vuggy reservoir is 0.04, the proportion of "pore-type" pores is 0.1, and the proportion of "cavity-type" pores is 0.86.

[0081] 4) Set the distribution range of porosity in the porosity template. In this embodiment, the distribution range of porosity is 0 - 1.

[0082] 5) Set the fluid saturation data of the rock in the porosity template. In this embodiment, the water saturation is set to 0.2.

[0083] 6) Substitute the data collected in steps 1) and 2), the data of the proportion of the three pore structures set in step 3), the porosity data set in step 4), and the water saturation data set in step 5) into the Xu-Payne rock physics model, and calculate the longitudinal wave impedance of the fractured reservoir and the vuggy reservoir changing with the porosity data respectively. The specific steps include:

[0084] ① Substitute the mineral content and mineral modulus data of the carbonate rock into the Voigt-Reuss-Hill formula to calculate the bulk modulus and shear modulus of the rock skeleton of the mineral mixture. The Voigt-Reuss-Hill formula is:

[0085]

[0086]

[0087]

[0088] where M vrh is the equivalent mixture modulus, N is the number of mineral components of the rock, f i is the content of rock mineral i, and M i is the bulk modulus or shear modulus of rock mineral i.

[0089] ② Use the data of the proportion of pore structures and the porosity data to calculate the porosity of each of the three pore structures. The calculation formula is as follows:

[0090]

[0091] where when i takes 1 - 3, are the porosities of "fracture-type", "pore-type", and "cavity-type" pores respectively, and F iThey are the proportions of "seam type", "hole type", and "cavity type" pores respectively. is the porosity.

[0092] ③ Substitute the mineral mixture rock frame modulus, porosity data, and pore geometric aspect ratio data into the differential equivalent medium approximation model to calculate the dry rock modulus varying with porosity. The formula of the differential equivalent medium approximation model for the dry rock modulus is:

[0093]

[0094]

[0095] Among them, when i takes values from 1 to 3, K0 is the rock frame bulk modulus, μ0 is the rock frame shear modulus, K1 is the dry rock bulk modulus after adding "seam type" pores, μ1 is the dry rock shear modulus after adding "seam type" pores, K2 is the dry rock bulk modulus after adding "seam type" and "hole type" pores, μ2 is the dry rock shear modulus after adding "seam type" and "hole type" pores, K3 is the dry rock bulk modulus after adding "seam type", "hole type", and "cavity type" pores, μ3 is the dry rock shear modulus after adding "seam type", "hole type", and "cavity type" pores. They are the porosities of "seam type", "hole type", and "cavity type" pores respectively, P i and Q i are the geometric factors of "seam type", "hole type", and "cavity type" respectively. When the pore geometric aspect ratio is a fixed value, P i and Q i are constants.

[0096] ④ Substitute the formation temperature, formation pressure, formation water salinity, gas-oil ratio, API gravity, and gas gravity data into the Bazlte-Wang formula to calculate the fluid property data under reservoir conditions. The formula for calculating the crude oil velocity in the Bazlte-Wang formula is:

[0097]

[0098] Among them, V oil is the crude oil velocity, T is the formation temperature, P is the formation pressure, ρ * is the pseudo-density of the oil-bearing crude oil. The calculation formula of ρ * is:

[0099]

[0100]

[0101]

[0102] Among them, μ 0For API gravity, G is the gas gravity, and R G is the gas-oil ratio.

[0103] The calculation formula for crude oil density in the Bazlte-Wang formula is:

[0104]

[0105] The calculation formula for formation water velocity under reservoir conditions in the Bazlte-Wang formula is:

[0106] V b = V w + S(1170 - 9.6T + 0.055T 2 - 0.000085T 3 + 2.6P - 0.0029TP - 0.0476P 2 + S 1.5 (780 - 10P + 0.16P 2 ) - 1820S 2 )

[0107] where S is the formation water salinity measured in the laboratory, and V w is the pure water velocity.

[0108] The calculation formula for formation water density in the Bazlte-Wang formula is:

[0109] ρ b = ρ w + S{0.668 + 0.44S + 10 -6 [300P - 2400PS + T(80 + 3T - 3300S - 13P + 47PS)}

[0110] where ρ w is the pure water density.

[0111] ⑤ Substitute the fluid property data, water saturation data, and dry rock modulus data under reservoir conditions into the Gassmann fluid substitution formula to calculate the rock bulk modulus under the condition of rock saturated with fluid. The Gassmann fluid substitution formula is:

[0112]

[0113] where K sat is the rock bulk modulus when the rock is saturated with fluid; is the porosity; K d is the bulk modulus of the dry rock; K m is the bulk modulus of the rock skeleton; K f is the effective bulk modulus of the oil-water mixed fluid under reservoir conditions, and the calculation formula for K f is:

[0114]

[0115] where S w is the water saturation, K b is the bulk modulus of formation water, and K oil is the bulk modulus of oil:

[0116]

[0117]

[0118] ⑥ Substitute the data of rock mineral content, mineral density, porosity and water saturation into the density volume average equation to calculate the density of the rock when saturated with fluid. The density volume average equation is:

[0119]

[0120] where ρ m is the density of the rock skeleton, and the calculation formula is:

[0121]

[0122] where N is the number of mineral components of the rock, f i is the content of rock mineral i, and ρ i is the density of rock mineral i.

[0123] ⑦ Calculate the P-wave velocity of the rock when saturated with fluid by using the bulk modulus and density of the rock when saturated with fluid. The formula is:

[0124]

[0125] ⑧ Calculate the P-wave impedance data of the rock when saturated with fluid by using the P-wave velocity and density of the rock when saturated with fluid. The formula is:

[0126] Zp = V sat ρ sat

[0127] 7) Plot the P-wave impedance-porosity relationship diagrams of fractured reservoirs and vuggy reservoirs with the P-wave impedance as the abscissa and the porosity as the ordinate, and project the porosity and P-wave impedance sample points measured from the core into the diagrams. If there are obvious differences between the calculated P-wave impedance-porosity curve and the sample points measured from the core, return to step 3) and readjust the proportion of the three types of pores in the fractured reservoir or vuggy reservoir until the trend of the calculated P-wave impedance-porosity curve is consistent with that of the sample points measured from the core. Figure 2Among them, it can be seen that the sample points with larger porosity fit well with the longitudinal wave impedance-porosity relationship diagram of the pore-type reservoir, and the sample points with smaller porosity fit well with the longitudinal wave impedance-porosity relationship diagram of the fracture-type reservoir, which is consistent with the geological understanding.

[0128] 8) Using porosity as the independent variable and the calculated longitudinal wave impedance as the dependent variable, perform regression analysis and establish the fitting formulas of longitudinal wave impedance-porosity corresponding to the fracture-type reservoir and the pore-type reservoir respectively. In the embodiment, the regression formula of the fracture-type reservoir is:

[0129] Por = 6.589 * Zp -0.2862 -0.3985

[0130] The regression formula of the pore-type reservoir is:

[0131] Por = -0.1227 * Zp 0.2564 +1.5

[0132] 9) Select the sigmoid activation function as the weight function and use the activation function to unify the regression formulas of the fracture-type reservoir and the pore-type reservoir into one formula. In this embodiment, the selected activation function is:

[0133]

[0134] In the distribution range of small porosity, the fracture-type reservoir is mainly dominant, and in the distribution range of large porosity, the pore-type reservoir is mainly dominant. The specific activation function formula is ( Figure 3 ):

[0135]

[0136] Among them, Zp is the longitudinal wave impedance.

[0137] Using the activation function, the formula of the longitudinal wave impedance-porosity version can be obtained as;

[0138]

[0139] 10) Output the formula obtained in step 9, and this formula is the constructed carbonate rock porosity version. Figure 4 For the comparison of the established longitudinal wave impedance-porosity version and the projection of the longitudinal wave impedance-porosity sample points of the core test.

[0140] The above embodiments are only used to further illustrate the present invention and should not be construed as limiting the protection scope of the present invention. Researchers in the field can make some non-essential improvements and adjustments to the present invention according to the content of the present invention, and all should fall within the protection scope of the claims of the present invention.

Claims

1. A method for constructing a carbonate rock pore measurement template, characterized in that It includes the following steps: 1) Collect well logging data and reservoir condition parameters in the work area; 2) Collect laboratory test data of core and fluid properties, and the data includes rock porosity measurement values, rock longitudinal wave impedance measurement values, rock mineral modulus, three pore geometric aspect ratio data of the rock, rock mineral density, formation water salinity, API gravity, gas-oil ratio and gas gravity, where the three pore structures of the rock are "fracture type" pores, "pore type" pores and "cavity type" pores; 3) Set the proportion of the three pore structures in the fractured reservoir and the vuggy reservoir, where the fractured reservoir is a reservoir type with a relatively high proportion of "fracture type" pores, and the vuggy reservoir is a reservoir type with a relatively high proportion of "pore type" and "cavity type" pores; 4) Set the distribution range of porosity in the porosity template; 5) Set the water saturation data of the rock in the porosity template; 6) Substitute the data collected in steps 1) and 2), the data of the proportion of the three pore structures set in step 3), the distribution range of porosity set in step 4), and the water saturation data set in step 5) into the Xu-Payne rock physics model, and calculate the longitudinal wave impedance of the fractured reservoir and the vuggy reservoir changing with the porosity data respectively; 7) Take the longitudinal wave impedance as the abscissa and the porosity as the ordinate, and draw the longitudinal wave impedance-porosity relationship diagrams of the fractured reservoir and the vuggy reservoir respectively, and project the porosity and longitudinal wave impedance sample points measured by the core into the diagrams. If there are obvious differences between the calculated longitudinal wave impedance-porosity curve and the sample points measured by the core, return to step 3) and readjust the proportion values of the three pores in the fractured reservoir or the vuggy reservoir until the trend of the calculated longitudinal wave impedance-porosity curve becomes consistent with the sample points measured by the core; 8) Take the porosity as the independent variable and the calculated longitudinal wave impedance as the dependent variable, conduct regression analysis, and establish the fitting formulas of longitudinal wave impedance-porosity corresponding to the fractured reservoir and the vuggy reservoir respectively; 9) Select the sigmoid activation function as the weight function, and use the activation function to unify the regression formulas of the fractured reservoir and the vuggy reservoir into one formula, and the activation function formula is: f(x) = 1 / (1 + e^(-x)); 10) Output the formula obtained in step 9), and this formula is the constructed carbonate rock porosity template.

2. The method according to claim 1, wherein In step 1), collect well logging mineral content data, formation pressure data and formation temperature data.

3. The method according to claim 1, wherein Step 6) specifically includes: ① Substitute the mineral content and mineral modulus data of the carbonate rock into the Voigt-Reuss-Hill formula to calculate the rock frame bulk modulus and rock frame shear modulus of the mineral mixture; ② Use the proportion data of the pore structure and the porosity data to calculate the porosity of each of the three pore structures; ③ Substitute the rock frame modulus of the mineral mixture, the porosity data and the pore geometric aspect ratio data into the differential equivalent medium approximation model to calculate the dry rock modulus changing with the porosity; ④ Substitute the formation temperature, formation pressure, formation water salinity, gas-oil ratio, API gravity, and gas gravity data into the Bazlte-Wang formula to calculate the fluid property data under reservoir conditions; ⑤ Substitute the fluid property data under reservoir conditions, water saturation data, and dry rock modulus data into the Gassmann fluid substitution formula to calculate the bulk modulus of the rock under the condition of rock saturated with fluid; ⑥ Substitute the rock mineral content, mineral density, porosity, and water saturation data into the density volume average equation to calculate the density of the rock when saturated with fluid; ⑦ Use the bulk modulus of the rock when saturated with fluid and the density when saturated with fluid to calculate the P-wave velocity of the rock when saturated with fluid; ⑧ Use the P-wave velocity and density of the rock when saturated with fluid to calculate the P-wave impedance data of the rock when saturated with fluid.

4. The method according to claim 3, characterized in that In step ①, the Voigt-Reuss-Hill formula is: Among them, M vrh is the equivalent mixture modulus, N is the number of mineral components of the rock, and f i is the content of rock mineral i, and M i is the bulk modulus or shear modulus of rock mineral i.

5. The method according to claim 3, wherein In step ②, the formula is: Among them, when i takes values from 1 to 3, are the porosities of "seam type", "hole type" and "cavity type" pores respectively, and F i are the proportions of "seam type", "hole type" and "cavity type" pores respectively, is the porosity.

6. The method according to claim 3, wherein In step ③, the differential equivalent medium approximation model formula is: Among them, when i takes values from 1 to 3, K0 is the bulk modulus of the rock skeleton, μ0 is the shear modulus of the rock skeleton, K1 is the bulk modulus of the dry rock after adding "fracture-type" pores, μ1 is the shear modulus of the dry rock after adding "fracture-type" pores, K2 is the bulk modulus of the dry rock after adding "fracture-type" and "pore-type" pores, μ2 is the shear modulus of the dry rock after adding "fracture-type" and "pore-type" pores, K3 is the bulk modulus of the dry rock after adding "fracture-type", "pore-type" and "cavity-type" pores, μ3 is the shear modulus of the dry rock after adding "fracture-type", "pore-type" and "cavity-type" pores. are the porosities of "fracture-type", "pore-type" and "cavity-type" pores respectively, P i and Q i are the geometric factors of "fracture-type", "pore-type" and "cavity-type" pores respectively. When the geometric aspect ratio of the pores is a fixed value, P i and Q i are constants.

7. The method according to claim 3, wherein In step ④, the crude oil velocity calculation formula in the Bazlte-Wang formula is: Among them, V oil is the crude oil velocity, T is the formation temperature, P is the formation pressure, ρ * is the pseudo-density of the gas-bearing crude oil, and the calculation formula of ρ * is as follows: where ρ 0 is the API gravity, G is the gas gravity, and R G is the gas-oil ratio; The crude oil density calculation formula in the Bazlte-Wang formula is: The formation water velocity calculation formula under reservoir conditions in the Bazlte-Wang formula is: V b = V w + S(1170 - 9.6T + 0.055T 2 - 0.000085T 3 + 2.6P - 0.0029TP - 0.0476P 2 + S 1.5 (780 - 10P + 0.16P 2 ) - 1820S 2 ) where S is the formation water salinity measured in the laboratory, and V w is the pure water velocity; The formation water density calculation formula in the Bazlte-Wang formula is: ρ b = ρ w + S{0.668 + 0.44S + 10 -6 [300P - 2400PS + T(80 + 3T - 3300S - 13P + 47PS)} where ρ w is the density of pure water.

8. The method according to claim 3, wherein In step ⑤, the Gassmann fluid substitution formula is: Among them, K sat is the bulk modulus of the rock when it is saturated with fluid; is the porosity; K d is the bulk modulus of the dry rock; K m is the bulk modulus of the rock skeleton; K f is the effective bulk modulus of the oil-water mixed fluid under reservoir conditions, and the calculation formula of K f is: where S w is the water saturation, K b is the bulk modulus of the formation water, and K oil is the bulk modulus of the oil:

9. The method according to claim 3, characterized in that In step ⑥, the density volume average equation is: where ρ m is the rock matrix density, and the calculation formula is: Among them, N is the number of mineral components of the rock, f i is the content of rock mineral i, ρ i is the density of rock mineral i.

10. The method according to claim 3, wherein In step ⑦, the P-wave velocity calculation formula is: In step ⑧, the longitudinal wave impedance calculation formula is: Zp = V sat ρ sat .

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