Method, device and equipment for determining content of natural gas in rock and storage medium

Abstract

The invention discloses a method, device and equipment for determining the content of natural gas in rock and a storage medium, and belongs to the technical field of petroleum and natural gas extraction. The method includes: determining relative molecular mass of natural gas in rock; determining the total void space of the rock per unit mass; determining the first formation pressure of the oil field formation under the normal pressure state of the formation depth; determining a second formation pressure of the rock in a standard state; determining a first density of natural gas of the rock in a standard state; determining a first gas content of the rock in a standard state based on the relative molecular mass of the natural gas, the first density, the volume ratio of the natural gas in the rock, the total void space and the volume of the natural gas ratio per unit mole number; and converting the first gas content into a second gas content of the rock in an ideal state. According to the method, the influence of temperature on the gas content of the natural gas can be considered, namely, the accuracy of determining the second gas content is improved.

Description

Technical Field

[0001] This application relates to the field of oil and gas extraction technology, and in particular to a method, apparatus, equipment and storage medium for determining the natural gas content in rocks. Background Technology

[0002] Rocks, especially sedimentary rocks with pores, fissures, and caverns, contain abundant natural gas, and the natural gas content in rocks is a crucial parameter for evaluating natural gas resources and selecting favorable areas. Specifically, the natural gas content in rocks refers to the volume of natural gas contained in one ton of rock at 101.325 kPa and 25°C. Therefore, determining the natural gas content in rocks is a key focus of the industry. Summary of the Invention

[0003] This application provides a method, apparatus, device, and storage medium for determining the natural gas content in rocks, which can take into account the influence of temperature on the natural gas content, thus improving the accuracy of the determined second gas content. The technical solution is as follows:

[0004] On the one hand, a method for determining the natural gas content in rocks is provided, the method comprising:

[0005] Determine the relative molecular mass of natural gas in the rock;

[0006] Determine the rock density and total porosity of the rock, and based on the rock density and total porosity, determine the total pore space per unit mass of the rock;

[0007] Determine the formation water density and formation depth of the oilfield where the rock is located. Based on the formation water density and formation depth, determine the first formation pressure of the oilfield formation at the formation depth under normal pressure. The normal pressure state is a state where the temperature is a first preset temperature and the pressure is a first preset pressure.

[0008] Based on the first formation pressure and the formation coefficient of the oilfield formation, the second formation pressure of the rock under standard conditions is determined, wherein the standard conditions are the first preset temperature and the second preset pressure.

[0009] Based on the second formation pressure, the volume percentage of each component in the rock, and the density of other components besides the natural gas, the first density of the natural gas in the rock under standard conditions is determined;

[0010] The first gas content of the rock under standard conditions is determined based on the relative molecular mass of the natural gas, the first density, the volume percentage of the natural gas in the rock, the total pore space, and the volume percentage of natural gas per unit mole.

[0011] The first gas content is converted into the second gas content of the rock under ideal conditions, wherein the ideal conditions are the second preset temperature and the second preset pressure.

[0012] In one possible implementation, the method further includes:

[0013] Based on the first formation pressure, the volume percentage of each component in the rock, and the density of other components besides the natural gas, the second density of the natural gas in the rock under normal pressure is determined.

[0014] Based on the relative molecular mass of the natural gas, the second density, the volume percentage of the natural gas in the rock, and the total void space, the second molar number of the natural gas under normal pressure is determined;

[0015] Based on the second molar number and the volume occupied by natural gas per unit molar number, the third gas content of the rock under normal pressure is determined.

[0016] In another possible implementation, determining the total pore space per unit mass of the rock based on the rock density and the total porosity includes:

[0017] Based on the rock density and the total porosity, the total pore space per unit mass of the rock is determined using the following formula:

[0018] Formula 1:

[0019] Where V represents the total pore space of the rock, m represents the mass of the rock per unit area, and ρ 岩石 The density of the rock is indicated. This represents the total porosity.

[0020] In another possible implementation, determining the first gas content of the rock under standard conditions based on the relative molecular mass of the natural gas, the first density, the volume fraction of the natural gas in the rock, the total pore space, and the volume fraction of natural gas per unit mole includes:

[0021] Based on the relative molecular mass of the natural gas, the first density, the volume fraction of the natural gas in the rock, and the total void space, the first mole number of the natural gas under standard conditions is determined using the following formula:

[0022] Formula 2: n 标准 =B 天然气 *ρ1 天然气 *V1 / M

[0023] Based on the first number of moles and the volume occupied by natural gas per unit number of moles, the first gas content of the rock under standard conditions is determined by the following formula three;

[0024] Formula 3: Q 标准 =n 标准 *V2

[0025] Where, n 标准 B represents the first mole number. 天然气 ρ1 represents the relative molecular mass of the natural gas. 天然气 V1 represents the first density, V1 represents the volume percentage of the natural gas in the rock, M represents the total pore space, and Q represents the total pore space. 标准 V1 represents the first gas content, and V2 represents the volume occupied by the unit number of moles of natural gas.

[0026] In another possible implementation, converting the first gas content into a second gas content of the rock under ideal conditions includes:

[0027] Based on the first temperature of the rock under standard conditions, the second temperature of the rock under ideal conditions, and the first gas content, the first gas content is converted into the second gas content of the rock under ideal conditions using the following formula:

[0028] Formula 4: T1 / V3 = T2 / V4

[0029] Wherein, T1 represents the first temperature, T2 represents the second temperature, V3 represents the first gas content, and V4 represents the second gas content.

[0030] In another possible implementation, the components of the rock include natural gas, crude oil, and formation water;

[0031] The determination of the first density of natural gas in the rock under standard conditions based on the second formation pressure, the volume percentage of each component in the rock, and the densities of components other than the natural gas includes:

[0032] Based on the second formation pressure, the volume percentage of natural gas, the volume percentage of crude oil, the volume percentage of formation water, the density of crude oil, and the density of formation water, the first density of natural gas in the rock under standard conditions is determined using the following formula five:

[0033] Formula 5: P 标准 = (B 天然气 ρ1 天然气 +B 原油 ρ 原油 +B 地层水 ρ 地层水 )gΔh

[0034] Among them, P 标准 B represents the second formation pressure. 天然气 ρ1 represents the volume percentage of natural gas. 天然气 B represents the first density of the natural gas. 原油 ρ represents the volume percentage of crude oil. 原油 B represents the density of crude oil. 地层水 ρ represents the volume percentage of formation water. 地层水 The density of the formation water is represented by g, the gravity coefficient is represented by Δh, and the depth of the formation is represented by Δh.

[0035] On the other hand, an apparatus for determining the natural gas content in a rock is provided, the apparatus comprising:

[0036] The first determining module is used to determine the relative molecular mass of natural gas in the rock;

[0037] The second determining module is used to determine the rock density and total porosity of the rock, and based on the rock density and total porosity, to determine the total void space per unit mass of the rock;

[0038] The third determining module is used to determine the formation water density and formation depth of the oil field where the rock is located, and based on the formation water density and formation depth, to determine the first formation pressure of the oil field formation at the formation depth under normal pressure, wherein the normal pressure state is a state where the temperature is a first preset temperature and the pressure is a first preset pressure.

[0039] The fourth determining module is used to determine the second formation pressure of the rock under standard conditions based on the first formation pressure and the formation coefficient of the oilfield formation. The standard conditions are the state where the temperature is the first preset temperature and the pressure is the second preset pressure.

[0040] The fifth determining module is used to determine the first density of natural gas in the rock under standard conditions based on the second formation pressure, the volume percentage of each component in the rock, and the density of other components besides the natural gas.

[0041] The sixth determining module is used to determine the first gas content of the rock under standard conditions based on the relative molecular mass of the natural gas, the first density, the volume ratio of the natural gas in the rock, the total void space, and the volume ratio of natural gas per unit mole.

[0042] The conversion module is used to convert the first gas content into the second gas content of the rock under ideal conditions, wherein the ideal conditions are the second preset temperature and the second preset pressure.

[0043] In one possible implementation, the device further includes:

[0044] The seventh determining module is used to determine the second density of natural gas in the rock under normal pressure based on the first formation pressure, the volume percentage of each component in the rock, and the density of other components besides the natural gas.

[0045] The eighth determining module is used to determine the second molar number of the natural gas under normal pressure based on the relative molecular mass of the natural gas, the second density, the volume percentage of the natural gas in the rock, and the total void space.

[0046] The ninth determining module is used to determine the third gas content of the rock under normal pressure based on the second molar number and the volume occupied by natural gas per unit molar number.

[0047] In another possible implementation, the second determining module is used to determine the total pore space per unit mass of the rock based on the rock density and the total porosity using the following formula:

[0048] Formula 1:

[0049] Where V represents the total pore space of the rock, m represents the mass of the rock per unit area, and ρ 岩石 The density of the rock is indicated. This represents the total porosity.

[0050] In another possible implementation, the sixth determining module is used to determine the first mole number of the natural gas under standard conditions based on the relative molecular mass of the natural gas, the first density, the volume fraction of the natural gas in the rock, and the total void space, using the following formula:

[0051] Formula 2: n 标准 =B 天然气 *ρ1 天然气 *V1 / M

[0052] Based on the first number of moles and the volume occupied by natural gas per unit number of moles, the first gas content of the rock under standard conditions is determined by the following formula three;

[0053] Formula 3: Q 标准 =n 标准 *V2

[0054] Where, n 标准 B represents the first mole number. 天然气 ρ1 represents the relative molecular mass of the natural gas. 天然气V1 represents the first density, V1 represents the volume percentage of the natural gas in the rock, M represents the total pore space, and Q represents the total pore space. 标准 V1 represents the first gas content, and V2 represents the volume occupied by the unit number of moles of natural gas.

[0055] In another possible implementation, the conversion module is used to convert the first gas content into the second gas content of the rock under ideal conditions based on the first temperature of the rock under standard conditions, the second temperature of the rock under ideal conditions, and the first gas content, using the following formula four:

[0056] Formula 4: T1 / V3 = T2 / V4

[0057] Wherein, T1 represents the first temperature, T2 represents the second temperature, V3 represents the first gas content, and V4 represents the second gas content.

[0058] In another possible implementation, the components of the rock include natural gas, crude oil, and formation water;

[0059] The fifth determining module is used to determine the first density of natural gas in the rock under standard conditions based on the second formation pressure, the volume ratio of natural gas, the volume ratio of crude oil, the volume ratio of formation water, the density of crude oil, and the density of formation water, using the following formula five:

[0060] Formula 5: P 标准 = (B 天然气 ρ1 天然气 +B 原油 ρ 原油 +B 地层水 ρ 地层水 )gΔh

[0061] Among them, P 标准 B represents the second formation pressure. 天然气 ρ1 represents the volume percentage of natural gas. 天然气 B represents the first density of the natural gas. 原油 ρ represents the volume percentage of crude oil. 原油 B represents the density of crude oil. 地层水 ρ represents the volume percentage of formation water. 地层水 The density of the formation water is represented by g, the gravity coefficient is represented by Δh, and the depth of the formation is represented by Δh.

[0062] On the other hand, a computer device is provided, the computer device including a processor and a memory, the memory storing at least one piece of program code, the at least one piece of program code being loaded and executed by the processor to implement the above-described method for determining the natural gas content in rocks.

[0063] On the other hand, a computer-readable storage medium is provided, wherein at least one piece of program code is stored therein, the at least one piece of program code being loaded and executed by a processor to implement the above-described method for determining the natural gas content in rocks.

[0064] On the other hand, a computer program product is provided, the product storing at least one piece of program code, the at least one piece of program code being executed by a processor to implement the above-described method for determining the natural gas content in rocks.

[0065] In this embodiment, since the temperature is the same under normal pressure and under standard conditions, but the pressure is different, the first formation pressure under normal pressure and the formation coefficient used to characterize the pressure relationship can be used to convert the first formation pressure under normal pressure into the second formation pressure under standard conditions. The first gas content under standard conditions can be determined based on the second formation pressure. However, the pressure is the same under standard conditions and under ideal conditions, but the temperature is different. Based on the relationship between the temperatures under standard conditions and ideal conditions, the first gas content can be converted into the second gas content under ideal conditions. This method can take into account the influence of temperature on the gas content of natural gas, thus improving the accuracy of the determined second gas content.

[0066] It should be understood that the above general description and the following detailed description are merely exemplary and do not limit this disclosure. Attached Figure Description

[0067] Figure 1 This is a flowchart illustrating a method for determining the natural gas content in rocks, as shown in an exemplary embodiment of this application;

[0068] Figure 2 This is a schematic diagram illustrating natural gas in rock, as shown in an exemplary embodiment of this application;

[0069] Figure 3 This is a flowchart illustrating a method for determining the natural gas content in rocks, as shown in an exemplary embodiment of this application;

[0070] Figure 4 This is a block diagram illustrating an apparatus for determining the natural gas content in rock, as shown in an exemplary embodiment of this application.

[0071] Figure 5 This is a block diagram illustrating a computer device in an exemplary embodiment of this application. Detailed Implementation

[0072] To make the technical solution and advantages of this application clearer, the embodiments of this application will be described in further detail below.

[0073] The terms "first," "second," "third," and "fourth," etc., used in the specification, claims, and accompanying drawings of this application are used to distinguish different objects, not to describe a specific order. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover non-exclusive inclusion. For example, a process, method, system, product, or apparatus that includes a series of steps or units is not limited to the listed steps or units, but may optionally include steps or units not listed, or may optionally include other steps or units inherent to these processes, methods, products, or apparatuses.

[0074] It should be noted that all information (including but not limited to user device information, user personal information, etc.), data (including but not limited to data used for analysis, stored data, displayed data, etc.), and signals involved in this application have been authorized by the user or fully authorized by all parties, and the collection, use, and processing of related data must comply with the relevant laws, regulations, and standards of the relevant countries and regions. For example, the rock-related information involved in this application (including but not limited to rock density, total porosity, formation water density, formation depth, formation coefficient, volume percentage and density of various components in the rock, etc.) was obtained with full authorization.

[0075] Please refer to Figure 1 This document illustrates a flowchart of a method for determining the natural gas content in rock, as shown in an exemplary embodiment of this application. The execution entity of this embodiment can be a computer device. (Refer to...) Figure 1 The method includes:

[0076] Step 101: Determine the relative molecular mass of natural gas in the rock.

[0077] The relative molecular mass of natural gas is used to represent the mass of 1 mole of natural gas under standard conditions. Standard conditions are defined as a temperature of a first preset temperature and a pressure of a second preset pressure. The first preset temperature can be 0°C, and the second preset pressure can be 101.325 kPa. Accordingly, standard conditions refer to a temperature of 0°C and a pressure of 101.325 kPa. Natural gas contains multiple components; therefore, this step can be: determining the volume percentage and relative molecular mass of each component in the natural gas; and then, using the following formula (Formula 6), weighted summing of the volume percentage and relative molecular mass of each component in the natural gas to obtain the relative molecular mass of the natural gas.

[0078] Formula 6: M = ΣBi * Mi

[0079] Where M represents the relative molecular mass of natural gas, Bi represents the volume percentage of the i-th component in natural gas, Mi represents the relative molecular mass of the i-th component in natural gas, and i is an integer greater than 1.

[0080] For example, natural gas contains methane, ethane, propane, carbon dioxide, and nitrogen; and the volume percentages of methane, ethane, propane, carbon dioxide, and nitrogen are 94.65%, 2.11%, 0.97%, 1.54%, and 0.57%, respectively. The relative molecular masses of methane, ethane, propane, carbon dioxide, and nitrogen are 16, 30, 44, and 28, respectively. Therefore, based on Formula Six above, the relative molecular mass of natural gas can be determined as:

[0081] M = 94.65% * 16 + 2.11% * 30 + 0.97% * 44 + 1.54% * 44 + 0.57% * 28 = 17.041, which means that under standard conditions (0℃, 101.325kPa), the mass of 1 mole of natural gas is 17.041g.

[0082] Step 102: Determine the rock density and total porosity of the rock, and based on the rock density and total porosity, determine the total void space per unit mass of rock.

[0083] Rock density and total porosity can be obtained through testing and analysis. Rock density represents the mass per unit volume of the basic aggregate phases (solid, liquid, and gaseous phases) of a rock. Total porosity refers to the ratio of the total pore volume to the total rock volume in an oil reservoir, expressed as a decimal or percentage, denoted by φ. Total pore space represents the space within the rock used to store fluids; the larger the total pore space, the more fluids are stored in the rock. In one possible implementation, the total pore space per unit mass of rock is determined based on rock density and total porosity using the following formula:

[0084] Formula 1:

[0085] Where V represents the total pore space of the rock, m represents the mass of a unit rock, and the mass of a unit rock can be 1 ton, and ρ 岩石 The density of the rock is indicated. This represents the total porosity.

[0086] For example, the density of the rock is 2.588 g / cm³, and the total porosity of the rock is... If the pore size is 4.5%, then based on Formula 1 above, the total pore space per unit mass of rock is:

[0087] V = 1,000,000 g / 2.58 g / cm³ 3 *4.5% / 1,000,000 = 0.0174m 3

[0088] Where 1,000,000 is the conversion factor between cubic centimeters and cubic meters.

[0089] Step 103: Determine the formation water density and formation depth of the oilfield where the rock is located. Based on the formation water density and formation depth, determine the first formation pressure of the oilfield formation at the formation depth under normal pressure. Normal pressure means the temperature is the first preset temperature and the pressure is the first preset pressure.

[0090] The first preset temperature can be 0℃, and the first preset pressure can be 0.1MPa; the formation water density is mainly affected by the content of dissolved salts in the water, and the formation water density is generally between 1.0-1.07 g / cm³. 3 Between; the formation water density of the oilfield where the rock is located can be obtained by measurement, and the formation depth can also be obtained by measurement. In one possible implementation, based on the formation water density and formation depth, the first formation pressure at the formation depth under normal pressure is determined by the following formula seven:

[0091] Formula 7: P 常压 =ρ 地层水 gΔh

[0092] Among them, P 常压 ρ represents the first formation pressure, g represents the gravity coefficient, and the value of g is 9.8 N / kg. 地层水 Δh represents the formation water density, and Δh represents the formation depth.

[0093] For example, the density of formation water is 1.01 g / cm³. 3 Given g = 9.8 N / kg and Δh = 3000 m, P is determined based on Formula 6. 常压 =1.01g / cm3*9.8N / kg*3000m=29.694Mpa.

[0094] Step 104: Based on the first formation pressure and the formation coefficient of the oilfield formation, determine the second formation pressure of the rock under standard conditions. The standard conditions are the state where the temperature is the first preset temperature and the pressure is the second preset pressure.

[0095] The first preset temperature can be 0℃, and the second preset pressure is 101.325 kPa; correspondingly, the standard state refers to a temperature of 0℃ and a pressure of 101.325 kPa. The formation coefficient is obtained from actual measurements of oil test and production materials; for example, the formation coefficient of this oilfield is 1.15. In one possible implementation, the product of the first formation pressure and the formation coefficient is determined to obtain the second formation pressure of the rock under the standard state. This implementation process can refer to Formula 8:

[0096] Formula 8: P 标准 =1.15*P 常压

[0097] Among them, P 标准P represents the pressure in the second formation. 常压 1.15 represents the first formation pressure, and 1.15 represents the formation coefficient.

[0098] Step 105: Based on the second formation pressure, the volume percentage of each component in the rock, and the density of components other than natural gas, determine the first density of natural gas in the rock under standard conditions.

[0099] For example, rock structure reference Figure 2 The rock contains natural gas, crude oil, and formation water; the volume percentages of natural gas, crude oil, and formation water, as well as the densities of crude oil and formation water, can be obtained from actual measurements using test oil production materials. In one possible implementation, this step can be: based on the second formation pressure, the volume percentages of natural gas, crude oil, and formation water, the density of crude oil, and the density of formation water, the first density of natural gas in the rock under standard conditions is determined using the following formula five:

[0100] Formula 5: P 标准 = (B 天然气 ρ1 天然气 +B 原油 ρ 原油 +B 地层水 ρ 地层水 )gΔh

[0101] Among them, P 标准 B represents the pressure in the second formation. 天然气 ρ1 represents the volume percentage of natural gas. 天然气 B represents the first density of the natural gas. 原油 ρ represents the volume percentage of crude oil. 原油 B represents the density of crude oil. 地层水 ρ represents the volume percentage of formation water. 地层水 Δh represents the formation water density, g represents the gravity coefficient, and g can take the value of 9.8 N / Kg, and Δh represents the formation depth.

[0102] In another possible implementation, based on the formation water density and formation coefficient of the oil field where the rock is located, as well as the volume percentage of each component in the rock and the density of other components besides natural gas, the first density of natural gas in the rock under standard conditions is determined by the following formula nine:

[0103] Formula 9: 1.15*ρ 地层水 gΔh=(B 天然气 ρ1 天然气 +B 原油 ρ 原油 +B 地层水 ρ 地层水 )gΔh

[0104] Where 1.15 represents the formation coefficient, and B 天然气 B represents the volume percentage of natural gas. 原油 B represents the volume percentage of crude oil. 地层水 ρ1 represents the volume percentage of formation water. 天然气 ρ represents the first density. 原油 ρ represents the density of crude oil. 地层水 This indicates the density of formation water.

[0105] Step 106: Determine the first gas content of the rock under standard conditions based on the relative molecular mass of natural gas, first density, volume fraction of natural gas in the rock, total pore space, and volume fraction of natural gas per mole.

[0106] This step can be achieved through the following steps (1) and (2), including:

[0107] (1) Based on the relative molecular mass, first density, volume fraction of natural gas in rock, and total pore space of natural gas, the first mole number of natural gas under standard conditions is determined by the following formula:

[0108] Formula 2: n 标准 =B 天然气 *ρ1 天然气 *V1 / M

[0109] (2) Based on the first molar number and the volume occupied by natural gas per unit molar number, the first gas content of the rock under standard conditions is determined by the following formula three;

[0110] Formula 3: Q 标准 =n 标准 *V2

[0111] Where, n 标准 B represents the first mole number. 天然气 ρ1 represents the relative molecular mass of natural gas. 天然气 Let V represent the first density, V1 represent the volume fraction of natural gas in the rock, M represent the total pore space, and Q represent the total density. 标准 V1 represents the first gas content, and V2 represents the volume occupied by a unit number of moles of natural gas. The value of V2 can be 22.41 L / mol. Accordingly, Formula 3 can be transformed into: Q 标准 =n 标准 *22.41.

[0112] For example, the first density ρ1 天然气 =1.9895g / cm 3 B 天然气 =20%, V1=0.0174m 3 Since M = 17.041, the first gas content is determined to be 9.10 m³. 3Specifically, it is calculated using the following formula:

[0113] Q 标准 =B 天然气 *ρ1 天然气 *V / M*22.41(L)=20%*1.9895g / cm 3 *0.0174m 3 / 17.041*22.41L / mol.

[0114] Step 107: Convert the first gas content into the second gas content of the rock under ideal conditions, wherein the ideal conditions are the second preset temperature and the second preset pressure.

[0115] The second preset temperature can be 25℃, and the second preset voltage can be 101.325kPa. According to the ideal gas equation PV=nRT, where T is the absolute temperature in K, T(K)=273.15+t(℃), the gas content per unit mass of rock under standard conditions at 0℃ and 101.325kPa is converted to the gas content per unit mass of rock under conditions of 101.325kPa and 25℃. The surface pressure P and molar mass n remain unchanged, and R is a constant. The conversion formula simplifies to P / nR=T / V, that is, T 0℃ / V 0℃ =T 25℃ / V 25℃ Accordingly, this step can be:

[0116] Based on the first temperature of the rock under standard conditions, the second temperature of the rock under ideal conditions, and the first gas content, the first gas content is converted into the second gas content of the rock under ideal conditions using the following formula:

[0117] Formula 4: T1 / V3 = T2 / V4

[0118] Wherein, T1 represents the first temperature, T2 represents the second temperature, V3 represents the first gas content, and V4 represents the second gas content.

[0119] In this embodiment, since the temperature is the same under normal pressure and under standard conditions, but the pressure is different, the first formation pressure under normal pressure and the formation coefficient used to characterize the pressure relationship can be used to convert the first formation pressure under normal pressure into the second formation pressure under standard conditions. The first gas content under standard conditions can be determined based on the second formation pressure. However, the pressure is the same under standard conditions and under ideal conditions, but the temperature is different. Based on the relationship between the temperatures under standard conditions and ideal conditions, the first gas content can be converted into the second gas content under ideal conditions. This method can take into account the influence of temperature on the gas content of natural gas, thus improving the accuracy of the determined second gas content.

[0120] Please refer to Figure 3 This document illustrates a flowchart of a method for determining the natural gas content in rock, as shown in an exemplary embodiment of this application. (Reference) Figure 3 The method includes:

[0121] Step 301: The computer equipment determines the relative molecular mass of the natural gas in the rock.

[0122] In some embodiments, this step is the same as step 101, and will not be described again here.

[0123] Step 302: The computer equipment determines the rock density and total porosity of the rock, and based on the rock density and total porosity, determines the total void space per unit mass of rock.

[0124] In some embodiments, this step is the same as step 102, and will not be described again here.

[0125] Step 303: The computer equipment determines the formation water density and formation depth of the oilfield where the rock is located. Based on the formation water density and formation depth, the first formation pressure of the oilfield formation at the formation depth under normal pressure is determined. Normal pressure means that the temperature is the first preset temperature and the pressure is the first preset pressure.

[0126] In some embodiments, this step is the same as step 103, and will not be described again here.

[0127] Step 304: The computer equipment determines the second density of natural gas in the rock under normal pressure based on the first formation pressure, the volume percentage of each component in the rock, and the density of other components besides natural gas.

[0128] The rock contains natural gas, crude oil, and formation water; the volume percentages of these components, as well as the densities of crude oil and formation water, can be obtained through actual measurements using test oil and production materials. In one possible implementation, this step can be as follows: A computer device, based on the first formation pressure, the volume percentages of the rock's components, and the densities of components other than natural gas, determines the second density of natural gas in the rock under normal pressure using the following formula:

[0129] Formula 10: P 常压 = (B 天然气 ρ2 天然气 +B 原油 ρ 原油 +B 地层水 ρ 地层水 )gΔh

[0130] Where, ρ 地层水 P represents the density of formation water. 常压 B represents the first formation pressure. 天然气 ρ2 represents the volume percentage of natural gas. 天然气 B represents the second density of the natural gas. 原油 ρ represents the volume percentage of crude oil. 原油 B represents the density of crude oil. 地层水 ρ represents the volume percentage of formation water. 地层水 Δh represents the formation water density, g represents the gravity coefficient, and g can take the value of 9.8 N / Kg, and Δh represents the formation depth.

[0131] In another possible implementation, the computer device determines the second density of natural gas in the rock under normal pressure based on the density of formation water, the volume percentage of each component in the rock, and the densities of components other than natural gas, using the following formula eleven:

[0132] Formula 11: ρ 地层水 gΔh=(B 天然气 ρ2 天然气 +B 原油 ρ 原油 +B 地层水 ρ 地层水 )gΔh

[0133] Where, ρ 地层水 B represents the density of formation water. 天然气 ρ2 represents the volume percentage of natural gas. 天然气 B represents the second density of the natural gas. 原油 ρ represents the volume percentage of crude oil. 原油 B represents the density of crude oil. 地层水 ρ represents the volume percentage of formation water. 地层水Δh represents the formation water density, g represents the gravity coefficient, and g can take the value of 9.8 N / Kg, and Δh represents the formation depth.

[0134] For example, under certain formation conditions, the volume percentage of natural gas is 20%, crude oil is 30%, and formation water is 50%, with the density of crude oil being 0.862 g / cm³. 3 The density of the formation water is 1.01 g / cm³. 3 According to the formula for atmospheric pressure formation, if the density of formation water in the overlying strata of a certain rock is uniform, then to maintain an atmospheric pressure state, the combined density of oil, gas, and water within the rock (i.e., at a certain depth) should be equivalent to the density of formation water. According to Formula Eleven: ρ 地层水 gΔh=(B 天然气 ρ2 天然气 +B 原油 ρ 原油 +B 地层水 ρ 地层水 )gΔh, derive ρ2 under normal pressure formation conditions 天然气 =1.232g / cm 3 .

[0135] Step 305: The computer device determines the second mole number of natural gas under normal pressure based on the relative molecular mass, second density, volume fraction of natural gas in the rock, and total void space of natural gas.

[0136] Since the mass of 1 mol of any gas under standard conditions (0℃, 101.325 kPa) is equal to its molar mass, and its volume occupied is approximately 22.41 L / mol, the gas content per unit mass of rock (1 ton) under standard conditions (0℃, 101.325 kPa) is (under standard conditions at 0℃, 101.325 kPa). Accordingly, this step can be: Based on the relative molecular mass of natural gas, its second density, the volume percentage of natural gas in the rock, and the total pore space, the computer equipment determines the second molar number of natural gas under normal pressure using the following formula:

[0137] Formula 12: n 常压 =B 天然气 *ρ2 天然气 *V1 / M

[0138] Where, n 常压 B represents the second mole number. 天然气 ρ² represents the relative molecular mass of natural gas. 天然气 V1 represents the second density, V1 represents the volume percentage of natural gas in the rock, and M represents the total pore space.

[0139] Step 306: The computer equipment determines the third gas content of the rock under normal pressure based on the second molar number and the volume occupied by natural gas per unit molar number.

[0140] The computer equipment determines the third gas content of the rock under standard conditions based on the volume occupied by the second molar number and the unit molar number of natural gas using the following formula thirteen.

[0141] Formula 13: Q 常压 =n 常压 *V2

[0142] Where, n 常压 B represents the second mole number. 天然气 V represents the relative molecular mass of natural gas, and V2 represents the volume occupied by one mole of natural gas. The value of V2 can be 22.41 L / mol. Accordingly, Formula XIII can be transformed into: Q 常压 =n 常压 *22.41. For example, Q 常压 =B 天然气 *ρ2 天然气 *V / M*22.41(L); Correspondingly, Q 常压 =20% * 1.232 g / cm³ 3 *0.0174m 3 / 17.041*22.41L / mol=5.64m 3 .

[0143] In this embodiment of the application, the computer device combines the third gas content and the subsequently calculated second gas content to form the gas content information of natural gas, thereby realizing the calculation of natural gas content (i.e., the third gas content) in rocks under normal pressure conditions, thus enriching the evaluation index of natural gas content.

[0144] Step 307: The computer equipment determines the second formation pressure of the rock under standard conditions based on the first formation pressure and the formation coefficient of the oilfield formation. The standard conditions are the state where the temperature is the first preset temperature and the pressure is the second preset pressure.

[0145] In some embodiments, this step is the same as step 104, and will not be described again here.

[0146] Step 308: The computer equipment determines the first density of natural gas in the rock under standard conditions based on the second formation pressure, the volume percentage of each component in the rock, and the density of other components besides natural gas.

[0147] In some embodiments, this step is the same as step 105, and will not be described again here.

[0148] Step 309: The computer device determines the first gas content of the rock under standard conditions based on the relative molecular mass of natural gas, the first density, the volume percentage of natural gas in the rock, the total pore space, and the volume percentage of natural gas per unit mole.

[0149] In some embodiments, this step is the same as step 106, and will not be described again here.

[0150] Step 310: The computer equipment converts the first gas content into the second gas content of the rock under ideal conditions, where the ideal conditions are the second preset temperature and the second preset pressure.

[0151] In some embodiments, this step is the same as step 107, and will not be described again here.

[0152] In this embodiment, since the temperature is the same under normal pressure and under standard conditions, but the pressure is different, the first formation pressure under normal pressure and the formation coefficient used to characterize the pressure relationship can be used to convert the first formation pressure under normal pressure into the second formation pressure under standard conditions. The first gas content under standard conditions can be determined based on the second formation pressure. However, the pressure is the same under standard conditions and under ideal conditions, but the temperature is different. Based on the relationship between the temperatures under standard conditions and ideal conditions, the first gas content can be converted into the second gas content under ideal conditions. This method can take into account the influence of temperature on the gas content of natural gas, thus improving the accuracy of the determined second gas content.

[0153] Furthermore, this method is simple and quick, applicable to the calculation of natural gas content in standard oil and gas fields under normal pressure, which is helpful for the evaluation of natural gas resources. Moreover, the embodiments of this application can also include the calculation of natural gas content in rocks under normal pressure conditions (i.e., the third gas content), thereby enriching the evaluation indicators for natural gas content.

[0154] Please refer to Figure 4 The diagram illustrates a block diagram of an apparatus for determining the natural gas content in rock, as shown in an exemplary embodiment of this application. The system includes:

[0155] The first determining module 401 is used to determine the relative molecular mass of natural gas in the rock;

[0156] The second determining module 402 is used to determine the rock density and total porosity of the rock, and based on the rock density and total porosity, to determine the total pore space per unit mass of rock.

[0157] The third determining module 403 is used to determine the formation water density and formation depth of the oil field where the rock is located. Based on the formation water density and formation depth, it determines the first formation pressure of the oil field formation at the formation depth under normal pressure. The normal pressure state is the state where the temperature is the first preset temperature and the pressure is the first preset pressure.

[0158] The fourth determining module 404 is used to determine the second formation pressure of the rock under standard conditions based on the first formation pressure and the formation coefficient of the oilfield formation. The standard conditions are the state where the temperature is the first preset temperature and the pressure is the second preset pressure.

[0159] The fifth determining module 405 is used to determine the first density of natural gas in the rock under standard conditions based on the second formation pressure, the volume percentage of each component in the rock, and the density of other components besides natural gas.

[0160] The sixth determining module 406 is used to determine the first gas content of the rock under standard conditions based on the relative molecular mass of natural gas, the first density, the volume ratio of natural gas in the rock, the total pore space, and the volume ratio of natural gas per unit mole.

[0161] The conversion module 407 is used to convert the first gas content into the second gas content of the rock under ideal conditions, where the ideal conditions are the second preset temperature and the second preset pressure.

[0162] In one possible implementation, the device further includes:

[0163] The seventh determination module is used to determine the second density of natural gas in the rock under normal pressure based on the first formation pressure, the volume percentage of each component in the rock, and the density of other components besides natural gas.

[0164] The eighth determination module is used to determine the second mole number of natural gas under normal pressure based on the relative molecular mass of natural gas, the second density, the volume fraction of natural gas in the rock, and the total pore space.

[0165] The ninth determination module is used to determine the third gas content of the rock under normal pressure based on the second molar number and the volume occupied by natural gas per unit molar number.

[0166] In another possible implementation, the second determining module 402 is used to determine the total pore space per unit mass of rock based on the rock density and total porosity using the following formula:

[0167] Formula 1:

[0168] Where V represents the total pore space of the rock, m represents the mass of a unit rock, and ρ 岩石 Indicates rock density, This indicates the total porosity.

[0169] In another possible implementation, the sixth determining module 406 is used to determine the first mole number of natural gas under standard conditions based on the relative molecular mass of natural gas, the first density, the volume fraction of natural gas in the rock, and the total pore space, using the following formula:

[0170] Formula 2: n 标准 =B 天然气 *ρ1 天然气 *V1 / M

[0171] Based on the first molar number and the volume occupied by natural gas per unit molar number, the first gas content of the rock under standard conditions is determined by the following formula three;

[0172] Formula 3: Q 标准 =n 标准 *V2

[0173] Where, n 标准 B represents the first mole number. 天然气 ρ1 represents the relative molecular mass of natural gas. 天然气 Let V represent the first density, V1 represent the volume fraction of natural gas in the rock, M represent the total pore space, and Q represent the total density. 标准 V1 represents the first gas content, and V2 represents the volume occupied by a unit number of moles of natural gas.

[0174] In another possible implementation, conversion module 407 is used to convert the first gas content of the rock into the second gas content of the rock under ideal conditions based on the first temperature of the rock under standard conditions, the second temperature of the rock under ideal conditions, and the first gas content, using the following formula four:

[0175] Formula 4: T1 / V3 = T2 / V4

[0176] Where T1 represents the first temperature, T2 represents the second temperature, V3 represents the first gas content, and V4 represents the second gas content.

[0177] In another possible implementation, the various components in the rock include natural gas, crude oil, and formation water;

[0178] The fifth determining module 405 is used to determine the first density of natural gas in the rock under standard conditions based on the second formation pressure, the volume percentage of natural gas, the volume percentage of crude oil, the volume percentage of formation water, the density of crude oil, and the density of formation water, using the following formula:

[0179] Formula 5: P 标准 = (B 天然气 ρ1 天然气 +B 原油 ρ原油 +B 地层水 ρ 地层水 )gΔh

[0180] Among them, P 标准 B represents the pressure in the second formation. 天然气 ρ1 represents the volume percentage of natural gas. 天然气 B represents the first density of natural gas. 原油 ρ represents the volume percentage of crude oil. 原油 B represents the density of crude oil. 地层水 ρ represents the volume percentage of formation water. 地层水 Δh represents the formation water density, g represents the gravity coefficient, and Δh represents the formation depth.

[0181] In this embodiment, since the temperature is the same under normal pressure and under standard conditions, but the pressure is different, the first formation pressure under normal pressure and the formation coefficient used to characterize the pressure relationship can be used to convert the first formation pressure under normal pressure into the second formation pressure under standard conditions. The first gas content under standard conditions can be determined based on the second formation pressure. However, the pressure is the same under standard conditions and under ideal conditions, but the temperature is different. Based on the relationship between the temperatures under standard conditions and ideal conditions, the first gas content can be converted into the second gas content under ideal conditions. This method can take into account the influence of temperature on the gas content of natural gas, thus improving the accuracy of the determined second gas content.

[0182] Furthermore, this method is simple and quick, applicable to the calculation of natural gas content in normal pressure and standard oil and gas fields, and is helpful for the evaluation of natural gas resources.

[0183] It should be noted that the above-described apparatus for determining the natural gas content in rocks is only illustrated by the division of the functional modules described above. In practical applications, the functions can be assigned to different functional modules as needed, that is, the internal structure of the computer device can be divided into different functional modules to complete all or part of the functions described above. Furthermore, the apparatus for determining the natural gas content in rocks and the method for determining the natural gas content in rocks provided in the above embodiments belong to the same concept, and their specific implementation process is detailed in the method embodiments, which will not be repeated here.

[0184] Please refer to Figure 5 , Figure 5This illustration shows a structural block diagram of a computer device 500 provided in an exemplary embodiment of this application. The computer device 500 may be a portable mobile computer device, such as a smartphone, tablet computer, MP3 player (Moving Picture Experts Group Audio Layer III), MP4 player (Moving Picture Experts Group Audio Layer IV), laptop computer, or desktop computer. The computer device 500 may also be referred to as a user device, portable computer device, laptop computer device, desktop computer device, or other names.

[0185] Typically, computer device 500 includes a processor 501 and a memory 502.

[0186] Processor 501 may include one or more processing cores, such as a quad-core processor, an octa-core processor, etc. Processor 501 may be implemented using at least one hardware form selected from DSP (Digital Signal Processing), FPGA (Field-Programmable Gate Array), and PLA (Programmable Logic Array). Processor 501 may also include a main processor and a coprocessor. The main processor, also known as a CPU (Central Processing Unit), is used to process data in the wake-up state; the coprocessor is a low-power processor used to process data in the standby state. In some embodiments, processor 501 may integrate a GPU (Graphics Processing Unit), which is responsible for rendering and drawing the content required to be displayed on the screen. In some embodiments, processor 501 may also include an AI (Artificial Intelligence) processor, which is used to handle computational operations related to machine learning.

[0187] The memory 502 may include one or more computer-readable storage media, which may be non-transitory. The memory 502 may also include high-speed random access memory and non-volatile memory, such as one or more disk storage devices or flash memory devices. In some embodiments, the non-transitory computer-readable storage media in the memory 502 is used to store at least one piece of program code, which is executed by the processor 501 to implement the operations performed by the computer device in the in-vehicle display method provided in the method embodiments of this application.

[0188] In some embodiments, the computer device 500 may also optionally include a peripheral device interface 503 and at least one peripheral device. The processor 501, memory 502, and peripheral device interface 503 can be connected via a bus or signal line. Each peripheral device can be connected to the peripheral device interface 503 via a bus, signal line, or circuit board. Specifically, the peripheral device includes at least one of the following: a radio frequency circuit 504, a display screen 505, a camera assembly 506, an audio circuit 507, and a power supply 508.

[0189] Peripheral device interface 503 can be used to connect at least one I / O (Input / Output) related peripheral device to processor 501 and memory 502. In some embodiments, processor 501, memory 502 and peripheral device interface 503 are integrated on the same chip or circuit board; in some other embodiments, any one or two of processor 501, memory 502 and peripheral device interface 503 can be implemented on separate chips or circuit boards, which is not limited in this embodiment.

[0190] The radio frequency (RF) circuit 504 is used to receive and transmit RF (Radio Frequency) signals, also known as electromagnetic signals. The RF circuit 504 communicates with communication networks and other communication devices via electromagnetic signals. The RF circuit 504 converts electrical signals into electromagnetic signals for transmission, or converts received electromagnetic signals back into electrical signals. Optionally, the RF circuit 504 includes: an antenna system, an RF transceiver, one or more amplifiers, a tuner, an oscillator, a digital signal processor, a codec chipset, a user identity module card, etc. The RF circuit 504 can communicate with other computer devices through at least one wireless communication protocol. This wireless communication protocol includes, but is not limited to: the World Wide Web, metropolitan area networks, intranets, various generations of mobile communication networks (2G, 3G, 4G, and 5G), wireless local area networks, and / or WiFi (Wireless Fidelity) networks. In some embodiments, the RF circuit 504 may also include circuitry related to NFC (Near Field Communication), which is not limited in this application.

[0191] Display screen 505 is used to display a UI (User Interface). This UI may include graphics, text, icons, videos, and any combination thereof. When display screen 505 is a touch display screen, it also has the ability to collect touch signals on or above its surface. These touch signals can be input as control signals to processor 501 for processing. In this case, display screen 505 can also be used to provide virtual buttons and / or a virtual keyboard, also known as soft buttons and / or a soft keyboard. In some embodiments, there may be one display screen 505, disposed on the front panel of the computer device 500; in other embodiments, there may be at least two display screens, disposed on different surfaces of the computer device 500 or in a folded design; in still other embodiments, display screen 505 may be a flexible display screen, disposed on a curved or folded surface of the computer device 500. Furthermore, display screen 505 may be configured as a non-rectangular, irregular shape, i.e., a non-rectangular screen. Display screen 505 may be made of materials such as LCD (Liquid Crystal Display) or OLED (Organic Light-Emitting Diode).

[0192] The camera assembly 506 is used to acquire images or videos. Optionally, the camera assembly 506 includes a front-facing camera and a rear-facing camera. Typically, the front-facing camera is located on the front panel of the computer device, and the rear-facing camera is located on the back of the computer device. In some embodiments, there are at least two rear-facing cameras, which are any one of a main camera, a depth-sensing camera, a wide-angle camera, and a telephoto camera, to achieve background blurring by fusion of the main camera and the depth-sensing camera, panoramic shooting by fusion of the main camera and the wide-angle camera, VR (Virtual Reality) shooting, or other fusion shooting functions. In some embodiments, the camera assembly 506 may also include a flash. The flash can be a single-color temperature flash or a dual-color temperature flash. A dual-color temperature flash is a combination of a warm-light flash and a cool-light flash, which can be used for light compensation at different color temperatures.

[0193] The audio circuit 507 may include a microphone and a speaker. The microphone is used to collect sound waves from the user and the environment, converting the sound waves into electrical signals that are input to the processor 501 for processing, or input to the radio frequency circuit 504 for voice communication. For stereo sound acquisition or noise reduction purposes, multiple microphones may be used, each located in a different part of the computer device 500. The microphone may also be an array microphone or an omnidirectional microphone. The speaker is used to convert the electrical signals from the processor 501 or the radio frequency circuit 504 into sound waves. The speaker may be a conventional diaphragm speaker or a piezoelectric ceramic speaker. When the speaker is a piezoelectric ceramic speaker, it can convert electrical signals not only into audible sound waves but also into inaudible sound waves for purposes such as distance measurement. In some embodiments, the audio circuit 507 may also include a headphone jack.

[0194] Power supply 508 is used to supply power to the various components in computer device 500. Power supply 508 can be AC ​​power, DC power, a disposable battery, or a rechargeable battery. When power supply 508 includes a rechargeable battery, the rechargeable battery can be a wired rechargeable battery or a wireless rechargeable battery. A wired rechargeable battery is a battery that is charged via a wired line, while a wireless rechargeable battery is a battery that is charged via a wireless coil. The rechargeable battery can also be used to support fast charging technology.

[0195] In some embodiments, the computer device 500 further includes one or more sensors 509. The one or more sensors 509 include, but are not limited to, an accelerometer 510, a gyroscope 511, a pressure sensor 512, an optical sensor 513, and a proximity sensor 514.

[0196] Accelerometer 510 can detect the magnitude of acceleration along the three coordinate axes of a coordinate system established by computer device 500. For example, accelerometer 510 can be used to detect the components of gravitational acceleration along the three coordinate axes. Processor 501 can control display screen 505 to display the user interface in either a landscape or portrait view based on the gravitational acceleration signal acquired by accelerometer 510. Accelerometer 510 can also be used for games or for acquiring user motion data.

[0197] The gyroscope sensor 511 can detect the orientation and rotation angle of the computer device 500. The gyroscope sensor 511 can work in conjunction with the accelerometer sensor 510 to acquire 3D motion data from the user on the computer device 500. Based on the data acquired by the gyroscope sensor 511, the processor 501 can perform the following functions: motion sensing (e.g., changing the UI based on the user's tilt), image stabilization during shooting, game control, and inertial navigation.

[0198] The pressure sensor 512 can be disposed on the side bezel of the computer device 500 and / or on the lower layer of the display screen 505. When the pressure sensor 512 is disposed on the side bezel of the computer device 500, it can detect the user's grip signal on the computer device 500, and the processor 501 can perform left / right hand recognition or quick operation based on the grip signal collected by the pressure sensor 512. When the pressure sensor 512 is disposed on the lower layer of the display screen 505, the processor 501 can control the operable controls on the UI interface based on the user's pressure operation on the display screen 505. The operable controls include at least one of button controls, scroll bar controls, icon controls, and menu controls.

[0199] An optical sensor 513 is used to collect ambient light intensity. In one embodiment, the processor 501 can control the display brightness of the display screen 505 based on the ambient light intensity collected by the optical sensor 513. Specifically, when the ambient light intensity is high, the display brightness of the display screen 505 is increased; when the ambient light intensity is low, the display brightness of the display screen 505 is decreased. In another embodiment, the processor 501 can also dynamically adjust the shooting parameters of the camera assembly 506 based on the ambient light intensity collected by the optical sensor 513.

[0200] The proximity sensor 514, also known as a distance sensor, is typically located on the front panel of the computer device 500. The proximity sensor 514 is used to detect the distance between the user and the front of the computer device 500. In one embodiment, when the proximity sensor 514 detects that the distance between the user and the front of the computer device 500 is gradually decreasing, the processor 501 controls the display screen 505 to switch from a screen-on state to a screen-off state; when the proximity sensor 514 detects that the distance between the user and the front of the computer device 500 is gradually increasing, the processor 501 controls the display screen 505 to switch from a screen-off state to a screen-on state.

[0201] Those skilled in the art will understand that Figure 5 The structure shown does not constitute a limitation on the computer device 500, and may include more or fewer components than shown, or combine certain components, or use different component arrangements.

[0202] This application also provides a computer-readable storage medium storing at least one piece of program code, which is loaded and executed by a processor to implement the method for determining the natural gas content in rocks as described in any of the above implementations. Optionally, the storage medium may be a non-transitory computer-readable storage medium, such as ROM (Read-Only Memory), RAM (Random Access Memory), CD-ROM (Compact Disc Read-Only Memory), magnetic tape, floppy disk, and optical data storage devices.

[0203] This application also provides a computer program product that stores at least one piece of program code, which is loaded and executed by a processor to implement the method for determining the natural gas content in rocks as shown in the above embodiments.

[0204] In some embodiments, the computer program product involved in the present application can be deployed and executed on a computer device, or on multiple computer devices located in one location, or on multiple computer devices distributed in multiple locations and interconnected through a communication network. Multiple computer devices distributed in multiple locations and interconnected through a communication network can form a blockchain system.

[0205] Those skilled in the art will understand that all or part of the steps of the above embodiments can be implemented by hardware or by a program instructing related hardware. The program can be stored in a computer-readable storage medium, such as a read-only memory, a disk, or an optical disk.

[0206] The above description is only for the purpose of enabling those skilled in the art to understand the technical solution of this application, and is not intended to limit this application. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the protection scope of this application.

Claims

1. A method for determining the natural gas content in a rock, characterized in that, The method includes: Determine the relative molecular mass of natural gas in the rock; Determine the rock density and total porosity of the rock, and based on the rock density and total porosity, determine the total pore space per unit mass of the rock; Determine the formation water density and formation depth of the oilfield where the rock is located. Based on the formation water density and formation depth, determine the first formation pressure of the oilfield formation at the formation depth under normal pressure. The normal pressure state is a state where the temperature is a first preset temperature and the pressure is a first preset pressure. Based on the first formation pressure and the formation coefficient of the oilfield formation, the second formation pressure of the rock under standard conditions is determined, wherein the standard conditions are the first preset temperature and the second preset pressure. Based on the second formation pressure, the volume percentage of each component in the rock, and the density of other components besides the natural gas, the first density of the natural gas in the rock under standard conditions is determined; The first gas content of the rock under standard conditions is determined based on the relative molecular mass of the natural gas, the first density, the volume percentage of the natural gas in the rock, the total pore space, and the volume percentage of natural gas per unit mole. The first gas content is converted into the second gas content of the rock under ideal conditions, wherein the ideal conditions are the second preset temperature and the second preset pressure.

2. The method according to claim 1, characterized in that, The method further includes: Based on the first formation pressure, the volume percentage of each component in the rock, and the density of other components besides the natural gas, the second density of the natural gas in the rock under normal pressure is determined. Based on the relative molecular mass of the natural gas, the second density, the volume percentage of the natural gas in the rock, and the total void space, the second molar number of the natural gas under normal pressure is determined; Based on the second molar number and the volume occupied by natural gas per unit molar number, the third gas content of the rock under normal pressure is determined.

3. The method according to claim 1, characterized in that, The determination of the total pore space per unit mass of rock based on the rock density and the total porosity includes: Based on the rock density and the total porosity, the total pore space per unit mass of the rock is determined using the following formula: Formula 1: Where V represents the total pore space of the rock, m represents the mass of the rock per unit area, and ρ 岩石 The density of the rock is indicated. This represents the total porosity.

4. The method according to claim 1, characterized in that, The determination of the first gas content of the rock under standard conditions based on the relative molecular mass of the natural gas, the first density, the volume fraction of the natural gas in the rock, the total pore space, and the volume fraction of natural gas per unit mole includes: Based on the relative molecular mass of the natural gas, the first density, the volume fraction of the natural gas in the rock, and the total void space, the first mole number of the natural gas under standard conditions is determined using the following formula: Formula 2: n 标准 =B 天然气 *ρ1 天然气 *V1 / M Based on the first number of moles and the volume occupied by natural gas per unit number of moles, the first gas content of the rock under standard conditions is determined by the following formula three; Formula 3: Q 标准 =n 标准 *V2 Where, n 标准 B represents the first mole number. 天然气 ρ1 represents the relative molecular mass of the natural gas. 天然气 V1 represents the first density, V1 represents the volume percentage of the natural gas in the rock, M represents the total pore space, and Q represents the total pore space. 标准 V1 represents the first gas content, and V2 represents the volume occupied by the unit number of moles of natural gas.

5. The method according to claim 1, characterized in that, The step of converting the first gas content into a second gas content of the rock under ideal conditions includes: Based on the first temperature of the rock under standard conditions, the second temperature of the rock under ideal conditions, and the first gas content, the first gas content is converted into the second gas content of the rock under ideal conditions using the following formula: Formula 4: T1 / V3 = T2 / V4 Wherein, T1 represents the first temperature, T2 represents the second temperature, V3 represents the first gas content, and V4 represents the second gas content.

6. The method according to claim 1, characterized in that, The rock contains various components including natural gas, crude oil, and formation water. The determination of the first density of natural gas in the rock under standard conditions based on the second formation pressure, the volume percentage of each component in the rock, and the densities of components other than the natural gas includes: Based on the second formation pressure, the volume percentage of natural gas, the volume percentage of crude oil, the volume percentage of formation water, the density of crude oil, and the density of formation water, the first density of natural gas in the rock under standard conditions is determined using the following formula five: Formula Five: P 标准 = (B 天然气 ρ1 天然气 + B 原油 ρ 原油 + B 地层水 ρ 地层水 )gΔh Among them, P 标准 B represents the second formation pressure. 天然气 ρ1 represents the volume percentage of natural gas. 天然气 B represents the first density of the natural gas. 原油 ρ represents the volume percentage of crude oil. 原油 B represents the density of crude oil. 地层水 ρ represents the volume percentage of formation water. 地层水 The density of the formation water is represented by g, the gravity coefficient is represented by Δh, and the depth of the formation is represented by Δh.

7. An apparatus for determining the natural gas content in rocks, characterized in that, The device includes: The first determining module is used to determine the relative molecular mass of natural gas in the rock; The second determining module is used to determine the rock density and total porosity of the rock, and based on the rock density and total porosity, to determine the total void space per unit mass of the rock; The third determining module is used to determine the formation water density and formation depth of the oil field where the rock is located, and based on the formation water density and formation depth, to determine the first formation pressure of the oil field formation at the formation depth under normal pressure, wherein the normal pressure state is a state where the temperature is a first preset temperature and the pressure is a first preset pressure. The fourth determining module is used to determine the second formation pressure of the rock under standard conditions based on the first formation pressure and the formation coefficient of the oilfield formation. The standard conditions are the state where the temperature is the first preset temperature and the pressure is the second preset pressure. The fifth determining module is used to determine the first density of natural gas in the rock under standard conditions based on the second formation pressure, the volume percentage of each component in the rock, and the density of other components besides the natural gas. The sixth determining module is used to determine the first gas content of the rock under standard conditions based on the relative molecular mass of the natural gas, the first density, the volume ratio of the natural gas in the rock, the total void space, and the volume ratio of natural gas per unit mole. The conversion module is used to convert the first gas content into the second gas content of the rock under ideal conditions, wherein the ideal conditions are the second preset temperature and the second preset pressure.

8. A computer device, characterized in that, The computer device includes a processor and a memory, the memory storing at least one piece of program code, which is loaded and executed by the processor to implement the method for determining the natural gas content in rock as described in any one of claims 1 to 6.

9. A computer-readable storage medium, characterized in that, The storage medium stores at least one piece of program code, which is loaded and executed by a processor to implement the method for determining the natural gas content in rocks as described in any one of claims 1 to 6.

10. A computer program product, characterized in that, The product stores at least one piece of program code, which is executed by a processor to implement the method for determining the natural gas content in rocks as described in any one of claims 1 to 6.

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