Method and system for predicting underground deep oil-gas phase state

Abstract

The invention relates to an underground deep oil-gas phase state prediction method and system, and the method comprises the steps: 1, recovering a deep temperature field of a research region according to the ground temperature of the research region; 2, recovering a deep layer pressure field of the research area; 3, determining the fluid chemical composition of different stratum sections in each geological period; and 4, inputting fluid chemical composition and selecting a state equation through PVTsim software, and generating a predicted P-T phase diagram in combination with the recovered deep temperature field and the recovered deep pressure field to realize prediction of the underground deep oil-gas phase state. The method is beneficial for determining a high-quality reservoir or a dessert area in a research area, optimizing exploration and development deployment, reducing well digging risks and improving the success rate of exploration and development.

Description

TECHNICAL FIELD

[0001] The present application relates to a method and system for predicting the phase state of deep underground oil and gas, belonging to the technical field of oil and gas development. BACKGROUND

[0002] In recent years, deep oil and gas exploration has made a major breakthrough, revealing the exploration prospects of large and medium-sized oil fields. However, the composition of deep hydrocarbon fluid is complex, and the occurrence phase state is variable. Due to the level of understanding and technical conditions, its occurrence mechanism has not been systematically studied. It is of great significance to evaluate and predict the composition of oil and gas reservoirs under geological conditions, and then evaluate and predict their phase state characteristics, especially for tight oil and gas, deep oil and gas, poor mobility and low recovery of oil and gas reservoirs. It is more important to develop effective exploration and development programs and improve development efficiency.

[0003] High temperature and high pressure (PVT) experimental analysis of formation fluid is a key technology in oil and gas reservoir engineering, and is also the most effective and most widely used experimental method for analyzing fluid phase state. By obtaining formation fluid samples on site, PVT analyzer is used for phase state research, which can obtain various parameters of formation fluid under actual underground conditions, such as saturation pressure, gas oil ratio, fluid composition, viscosity and density, etc. In the field of theoretical calculation of fluid phase state, gas state equation is usually used to simulate the phase state change of fluid, combined with thermodynamic theory and phase equilibrium theory, such as calculating the key parameters of bubble point and dew point pressure. These parameters are crucial for the development and production strategy of oil and gas reservoirs, but the acquisition of parameters depends on the drilling of formation fluid samples. For the phase state of formation fluid that has not been drilled or has not obtained formation fluid data, it cannot be predicted and targeted drilling development cannot be carried out. SUMMARY

[0004] In view of the shortcomings of the prior art, the present application provides a method and system for predicting the phase state of deep underground oil and gas, which combines organic matter hydrocarbon generation prediction with PVTsim software to predict the underground oil and gas in unexplored and un-drilled areas, thereby helping to solve the problem of predicting the phase state of deep underground oil and gas.

[0005] Terminology: 1. PVTsim software: PVT simulation software, which can quantitatively simulate the composition distribution and phase state characteristics of oil and gas from deep underground reservoirs to standard conditions.

[0006] 2. PVT: pressure, volume, and temperature, respectively, which are important parameter combinations for describing the properties of oil and gas reservoir fluids in geology.

[0007] 3. Easy- R o Model: Easy- R oModel is a numerical simulation method based on chemical kinetics, which links temperature and Ro (organic matter maturity) through a series of chemical reactions of hydrocarbon generation of organic matter, and is used to invert the thermal history of sedimentary organic matter.

[0008] 4, P-T phase diagram: a diagram showing the phase state of a substance (oil and gas fluid, etc.) under temperature and pressure changes; The technical scheme of the present application is as follows: The first aspect of the present application provides a method for predicting the phase state of deep underground oil and gas, comprising: Step 1: restore the deep temperature field of the study area according to the geothermal gradient of the study area; Step 2: restore the deep pressure field of the study area; Step 3: determine the chemical composition of the fluid in different geological periods of different layers; Step 4: input the chemical composition of the fluid and select the equation of state through the PVTsim software, combine the restored deep temperature field and deep pressure field, and generate the predicted P-T phase diagram to realize the prediction of the phase state of deep underground oil and gas.

[0009] According to the present application, the deep temperature field of the study area is restored according to the geothermal gradient of the study area, comprising: According to the present geothermal gradient of the study area, the heat flow history and geothermal history of the study area are deduced, that is, based on Easy- R o The model restores the deep temperature field, comprising: Step 1.1: reconstruct the burial history of the study area, that is, according to the seismic logging data of the study area, obtain the depth and formation time of the study area, and determine the period of formation of the horizon and the present depth; Step 1.2: set the paleo-heat flow wherein Q0 is the present heat flow, represents the depth, represents a set of unknown numbers, t is time, and the paleo-geothermal is calculated by the formula as follows: ; wherein, represents the paleo-geothermal of the stratum at a depth of Z from the present time t, Ts is the surface temperature, is the thermal conductivity of the depth Z; The measured Ro, i.e. vitrinite reflectance, is used to detect and calibrate the paleo-geothermal, and the value of theta is adjusted so that the paleo-geothermal and the measured Ro satisfy the following relationship: ; wherein n is the total number of measured Ro, represents the measured Ro value of the kth point, represents the surface Ro value, Let Ro be the measured value at point j; This represents the time-temperature index at point k. Represents the time-temperature index at point j; where the time-temperature indexes of all points are... The calculation is as follows: ; Step 1.3: Compare the measured Ro with the paleogeothermal temperature. If the fit is good, that is, if the paleogeothermal temperature and the measured Ro satisfy the relationship... If the paleotemperature is the actual geothermal history experienced by the strata, then it is the deep temperature field; otherwise, repeat step 1.2 until the fitting degree is good.

[0010] According to a preferred embodiment of the present invention, restoring the deep pressure field of the study area includes: By measuring the homogenization temperature, formation temperature, liquid salinity, and pressure at the time of fluid inclusion formation, and then using the relevant temperature-pressure relationship established by the saline solution to reconstruct the paleostress pressure during the hydrocarbon accumulation period in the study area, as shown below: ; ; ; Where P represents paleopressure, i.e., the pressure at which the inclusions formed, and T represents the ascent temperature, i.e., the temperature at which the inclusions formed. h The homogenization temperature is represented by , m represents the molality of the salt; a1, a2, a3, and a4 are constants for the liquid salt. The paleopressure P was calculated, which is the recovered deep pressure field of the study area.

[0011] According to a preferred embodiment of the present invention, determining the fluid chemical composition of different geological periods in different strata includes: The process of generating hydrocarbons from organic matter is as follows: N It consists of a series of parallel first-order reactions, and each group has its own pre-exponential factor. Activation energy of reaction And set the initial hydrocarbon generation potential for each reaction as , i = 1, 2,..., N ; in time t At that time, the first i The amount of hydrocarbons generated by each reaction is X i The reaction rates are shown below: ; ; in, Indicates the first i The reaction rate in each reaction, A, represents the ith pre-exponential factor, P, is the pressure at which cracking to gas occurs, a A, represents the effect of pressure on the pre-exponential factor in the ith hydrocarbon generation reaction; R R, is the gas constant; T, is the absolute temperature; E, represents the ith reaction activation energy, A, represents the effect of pressure on the activation energy in the ith hydrocarbon generation reaction; isothermal heating was used , and is given by: ; By integrating the above equation, the ith reaction hydrocarbon generation i , X, is calculated and is given by: ; where, T 0 T, is the initial heating temperature; N The total hydrocarbon generation from N parallel reactions, X, is given by: ; where, X X, is the total hydrocarbon generation from all N N parallel reactions, N n, is the number of parallel first order reactions; The total oil generation from N kerogen oil generation parallel reactions, X0, is given by: ; where, X0, represents the ith reaction oil generation, X0, represents the original oil potential, A, represents the ith oil generation reaction pre-exponential factor, E, represents the ith oil generation reaction activation energy; The total gas generation from N kerogen gas generation parallel reactions, XG, is given by: ; where, XG, represents the ith reaction gas generation, XG, represents the original gas potential, A, represents the ith gas generation reaction pre-exponential factor, E, represents the ith gas generation reaction activation energy; The total gas generation from N oil cracking gas generation parallel reactions, X0G, is given by: ; where, X0G, represents the ith oil cracking gas generation parallel reaction total gas generation, X0G, represents the original total gas potential for oil cracking gas generation parallel reactions,​ represents the i-th oil cracking gas parallel reaction pre-exponential factor, represents the i-th oil cracking gas parallel reaction activation energy; The oil generation amount NOO and the gas generation amount TG of the organic matter are as follows: ; ; The hydrocarbon generation thermal simulation experiment through the gold tube is to heat the hydrocarbon source rocks in different layers of the research area, simulate the hydrocarbon generation process of the hydrocarbon source rocks underground, obtain the maximum yield and proportion of C1-C n , wherein C1 is the first hydrocarbon, and C n is the nth hydrocarbon; The oil generation amount NOO or the gas generation amount TG is multiplied by the maximum yield of C1 to C n to obtain the generation amount of each hydrocarbon, that is, the fluid chemical composition of each geological period in different layers.

[0012] According to the preferred embodiment of the present application, the PVTsim software is used to input the fluid chemical composition and select the state equation, combine the restored deep temperature field and deep pressure field to generate the predicted P-T phase diagram, and realize the prediction of the phase state of the deep underground oil and gas; including: The fluid chemical composition is input into the PVTsim software, the PR state equation or the SRK state equation is selected for calculation, the restored deep temperature field and deep pressure field are input, the oil and gas P-T phase diagram in different evolution periods is generated, and the phase state of the fluid is judged according to the oil and gas P-T phase diagram, that is, the prediction of the phase state of the oil and gas is realized.

[0013] A computer device includes a memory and a processor, the memory stores a computer program, and the processor realizes the steps of the prediction method of the phase state of the deep underground oil and gas when executing the computer program.

[0014] A computer readable storage medium stores a computer program, and the computer program realizes the steps of the prediction method of the phase state of the deep underground oil and gas when executed by a processor.

[0015] The second aspect of the present application provides a prediction system for the phase state of the deep underground oil and gas, including: The deep temperature field recovery module is configured to recover the deep temperature field of the research area according to the ground temperature of the research area; The deep pressure field recovery module is configured to recover the deep pressure field of the research area; The fluid chemical composition determination module is configured to determine the fluid chemical composition of each geological period in different layers; An oil and gas phase state prediction module is configured to: input fluid chemical composition and select a state equation through PVTsim software, combine the restored deep temperature field and deep pressure field, generate a predicted P-T phase diagram, and realize prediction of the oil and gas phase state in a deep underground.

[0016] The present application has the following beneficial effects: 1. Unlike PVT experiments through a small amount of underground oil and gas samples, the present application can realize prediction of the oil and gas phase state in different regions of multiple layers in a continuous period by using a simulation calculation method, and reduce exploration and development experiment cost.

[0017] 2. The oil and gas phase state in an area without a drilled well or a planned drilled well can be predicted, which is beneficial to determine a high-quality reservoir or a sweet spot area in a research area, optimize exploration and development deployment, reduce well drilling risk, and improve exploration and development success rate. BRIEF DESCRIPTION OF DRAWINGS

[0018] Figure 1 is a flow chart of the oil and gas phase state prediction method in a deep underground of the present application; Figure 2 is a comparison schematic diagram of a PVTsim software simulation phase diagram and a PVT experiment phase diagram; Figure 2 (a) in the figure is a PVTsim software simulation phase diagram, Figure 2 (b) in the figure is a PVT experiment phase diagram; Figure 3 is a schematic diagram of fitting effect of a hydrocarbon generation kinetics model of the present application; Figure 4 is a schematic diagram of prediction of the oil and gas phase state by combining a PVTsim software calculation phase diagram and a formation temperature and pressure field of the present application. DETAILED DESCRIPTION

[0019] The present application is further described below by embodiments and in conjunction with the drawings, but is not limited thereto.

[0020] Embodiment 1 An oil and gas phase state prediction method in a deep underground, as shown in Figures 1-4 , comprises: Step 1: restoring a deep temperature field of a research area according to a research area temperature; Step 2: restoring a deep pressure field of the research area; Step 3: determining fluid chemical composition of different geological periods in different layers; Step 4: inputting the fluid chemical composition and selecting a state equation through PVTsim software, combining the restored deep temperature field and deep pressure field, generating a predicted P-T phase diagram, and realizing prediction of the oil and gas phase state in a deep underground.

[0021] Embodiment 2 The method for predicting the phase state of deep underground oil and gas as described in Example 1 differs in that: Based on the geothermal data of the study area, reconstruct the deep temperature field of the study area; including: This method reconstructs the thermal history of a study area using a combination of geothermal and geochemical techniques. It is an inversion method, where the heat flow history and geothermal history (i.e., the deep temperature field) of the study area (basin) are deduced from the current geothermal temperature, and this deduction is required to match geochemical data (such as vitrinite reflectance Ro). This process is typically performed using Easy- R o The method restores the maturation of organic matter, based on Easy- R o The model reconstructs the deep temperature field, including: Step 1.1: Reconstruct the stratigraphic history of the study area (including the erosion history of the stratigraphy), that is, based on the seismic logging data of the study area (data obtained by transmitting seismic waves and then detecting the transmitted and recovered waves), obtain the depth and formation time of the study area, and clarify the period of formation and current depth of the strata (such as clarifying which depth belongs to which stratum and how many millions of years ago it was formed). Step 1.2: Set the paleothermal flow Where Q0 is the current heat flow (the heat passing through a certain cross section per unit time). Indicates depth, Let t represent the unknown variable, and t be the time (geological age in Ma at a certain moment during the burial process). Based on the principle of heat conduction, the paleotemperature is calculated using the formula shown below: ; in, This represents the paleogeothermal temperature of the strata at a depth Z from the Earth's surface at a time t ago, where Ts is the surface temperature. Thermal conductivity at depth Z; Paleothermal temperature was measured and calibrated using vitrinite reflectance (an indicator of organic matter maturity, obtainable from data of the study area). The θ value was adjusted so that the paleothermal temperature and the measured Ro satisfy the following relationship: ; Where n is the total number of measured Ro, This represents the measured Ro value at the k-th point. , This represents the surface Ro value (usually taken as 0.2%). This represents the measured Ro value at point j; This represents the time-temperature index at point k. Represents the time-temperature index at point j; where the time-temperature indexes of all points are... The calculation is as follows: ; Step 1.3: Comparing the measured Ro with the paleo-geotemperature, if the fitting degree is good, i.e. the paleo-geotemperature and the measured Ro satisfy the relationship (k = 1, 2, …, n), the paleo-geotemperature is the actual geotemperature history experienced by the stratum, i.e. the deep temperature field; otherwise, repeat step 1.2 until the fitting degree is good.

[0022] Restoring the deep pressure field of the study area; including: Fluid inclusion records the temperature and pressure characteristics when the fluid formed the inclusion in the historical period. By measuring the homogenization temperature, the temperature when the fluid was formed, the liquid salinity and the pressure when the inclusion was formed, and according to the related isochoric equation of the salt water solution, the paleo-geotemperature of the study area during the hydrocarbon accumulation period is restored, as shown below: ; ; ; Wherein, P represents the paleo-pressure, i.e. the pressure when the inclusion was formed (10 -1 MPa), T represents the obtained temperature, i.e. the temperature when the inclusion was formed (℃, generally considered to be 15℃ higher than the homogenization temperature), T h represents the homogenization temperature (℃), m represents the mass molar concentration of salt (mol / kg); a1, a2, a3, a4 are constants of liquid salt; The paleo-pressure P is calculated, i.e. the deep pressure field of the study area is restored. The inclusions are in different strata, and by calculating the pressure when the inclusions in different strata were formed, the paleo-geotemperature during the period when the inclusions were formed can be obtained. When the number of inclusions is sufficient, the pressure of any stratum in any period can be obtained;

[0023] Determining the fluid chemical composition of different geological periods in different intervals; including: The pressure kinetic model is established by the parallel first-order reaction model, as shown below: ; Wherein, is the reaction rate of cracking of kerogen (crude oil) into gas; from the chemical kinetics principle, it can be seen that with the increase of pressure, the pre-exponential factor will be reduced and the reaction activation energy will be increased; based on the modeling idea of predecessors and the optimization application of kinetic parameters, the pressure factor is introduced into the Arrhenius formula, and the reaction rate is expressed as: ; Wherein, is the pressure (MPa) when cracking into gas, a、 respectively represent the pressure effect factor and the activation energy effect factor in the hydrocarbon generation reaction; R R is the gas constant, 8.31447 kJ·mol -1 ·K -1 ; T is the absolute temperature; E represents the reaction activation energy, and A is the pre-exponential factor; It is assumed that the process of hydrocarbon generation of organic matter is composed of N parallel first-order reactions, and each group has its own pre-exponential factor , reaction activation energy , and the original hydrocarbon generation potential corresponding to each reaction is set as , i = 1, 2,..., N ; at time t , the hydrocarbon generation amount of the i i th reaction is X i , and the reaction rate is as follows: ; ; Among them, represents the reaction rate in the i i th reaction, represents the i th pre-exponential factor, represents the i th reaction activation energy, represents the pressure effect factor on the activation energy in the i th hydrocarbon generation reaction; the uniform temperature rise is adopted , and the following is obtained: i ; ; Among them, T 0 represents the initial heating temperature; N The total hydrocarbon generation amount of the i th parallel reaction is as follows: ; X Among them, N X is the total hydrocarbon generation amount of all N N parallel reactions, and N is the number of parallel first-order reactions; The total oil generation amount XO of N kerogen oil generation parallel reactions is as follows: ; Among them, Xi represents the oil generation amount of the i th reaction, This represents the pre-exponential factor of the i-th oil-generating reaction. This represents the activation energy of the i-th oil-generating reaction; The total amount of biogas generated in N parallel kerogen biogas reactions, XG, is shown below: ; in, This represents the amount of anger generated by the i-th reaction. Indicates the original potential of life force. This represents the pre-exponential factor of the i-th angry reaction. This represents the activation energy of the i-th gas-generating reaction; The total gas production (XOG) of N parallel oil cracking gas generation reactions is shown below: ; in, This represents the total amount of gas generated in the i-th parallel oil cracking gas generation reaction. This indicates the initial total gas production potential of the parallel reaction of oil cracking and gas generation. This represents the pre-exponential factor of the i-th parallel reaction of oil cracking and gas generation. This represents the activation energy of the i-th parallel reaction for gas generation from oil cracking; The NOO and TG of organic matter are shown below: ; ; The hydrogen generation thermal simulation experiment using gold tubes involves heating source rocks from different layers in the study area to simulate the underground hydrogen generation process. This yields C1-C values ​​at different heating temperatures and time periods (similar to various geological periods from the start of hydrogen generation to the present). n The maximum yield and percentage (where n can be at least 14 bits, fully meeting the needs of PVTsim software calculations), where C1 is the first hydrocarbon, C n This is the nth hydrocarbon; Compare the NOO or TG production of oil with C1 to C2. n Multiply by the maximum yield to obtain the amount of each hydrocarbon generated, i.e. the fluid chemical composition of different geological periods in different layers (e.g., if the total oil production is 100g, the thermal simulation experiment of hydrocarbon generation in the gold tube shows that 1g of kerogen can generate 0.5g of CH4, 0.3g of C2H6, etc., so the amount of CH4, C2H6, etc. generated can be obtained).

[0024] Using PVTsim software, the fluid chemical composition is input and the equation of state is selected. Combined with the recovered deep temperature and pressure fields, a predicted PT phase diagram is generated, enabling the prediction of the phase states of deep underground oil and gas. This includes: The key to phase state simulation calculation is to obtain the equilibrium ratio under the corresponding reservoir temperature and pressure, and then convert it into fugacity to obtain the bubble dew point pressure through an iterative algorithm. The equilibrium ratio can be obtained by graphical method and calculation method. For the equilibrium constant under high temperature and high pressure conditions, the range and accuracy of graphical method cannot meet the requirements, while the calculation method based on thermodynamic model is more convenient and reasonable. The core of the calculation method is to select an appropriate equation of state (EOS), which has an important impact on the accuracy of phase state calculation results. The selection of equation of state and calculation simulation can be realized by PVTsim software. At present, the commonly used cubic equation of state for hydrocarbon fluid calculation includes PR (Peng-Robinson) equation of state, SRK (Soave-Redlich-Kwong) equation of state, and two types of equation of state modified by Peneloux. The state equations (cubic state equations) are either the PR (Peng-Robinson) state equations or the SRK (Soave-Redlich-Kwong) state equations. The PR equation of state is a modified version of the VDW equation of state. It has good predictive accuracy for oil-gas mixtures containing polar components and is applicable to the gas-liquid two-phase equilibrium calculation of mixtures; as shown below: ; Where P1 represents pressure (MPa), V m molar volume (m 3 / mol), b represents the molecular volume parameter (m 3 / mol), T1 represents temperature (K). Let represent the van der Waals force parameter, and R be the gas constant (8.31 MPa•cm³ / mol•K). The introduction of the temperature function a(T1) has a significant effect on improving the influence of complex molecular systems in hydrocarbons on the PVT phase characteristics. a(T1) is shown below: ; Where Tr is the comparison temperature, Tr=T1 / Tc, and Tc represents the critical temperature (K). A function of the material eccentricity factor, expressed as: ; Where ω represents the eccentricity factor; obviously, substances with different degrees of eccentricity have different... The introduction of the eccentricity factor ω enables the PR equation to be applicable to gas-liquid phase equilibrium calculations for mixtures containing nonpolar molecules and polar components, and it can predict liquid phase volume characteristics and fugacity relatively well. At the critical point, the values ​​of a(T1) and b in the PR equation of state are as follows: ; ; in, Indicates the critical temperature (K). Indicates the critical pressure (MPa); The SRK equation of state is also a modified version of the VDW equation of state, and it has good prediction accuracy for nonpolar or weakly polar oil-gas mixtures, as shown below: ; ; ; ; ; Where T2 represents temperature (K) and P2 represents pressure (MPa). b1 represents the van der Waals force parameter, and b1 represents the molecular volume parameter. A function representing the material eccentricity factor; Input the fluid chemical composition into the PVTsim software, select the PR equation of state or the SRK equation of state for calculation (PR has high accuracy in predicting oil-gas mixtures containing polar components, while SRK is suitable for non-polar or weakly polar components), and input the recovered deep temperature field and deep pressure field (formation temperature and pressure) to generate oil-gas PT phase diagrams in formations at different evolution stages (generated directly by the PVTsim software). Based on the oil-gas PT phase diagrams, determine the fluid phase state to predict the oil-gas phase state.

[0025] High-temperature and high-pressure physical property analysis (PVT) of formation fluids is the most widely used and effective method for fluid phase state research. By conducting PVT experiments on formation fluids (PVT is an existing analytical testing project that mainly studies the phase characteristics and physical properties of oil and gas by measuring their physical parameters under different pressures and temperatures), physical parameters are obtained, including the composition, volume coefficient, gas-oil ratio, average gas solubility coefficient, shrinkage rate, bubble dew point pressure, gas deviation coefficient, condensate volume, relative density of C7+ components, and molecular weight. This reveals the physical characteristics of hydrocarbon fluids under formation conditions, laying the foundation for formation fluid phase state characteristic analysis and phase state fitting calculations. PVT experiments include flash separation experiments, constant-mass expansion experiments, and constant-volume exhaustion experiments. The PVTsim software inputs the physical property parameters obtained from the PVT experiment analysis, and uses the fluid phase state theory calculation method (inputting the composition of the formation fluid obtained from the PVT experiment into the software, and then selecting the gas state equation for calculation to generate the calculated PT phase diagram). The phase diagram calculated by the PVTsim software is compared with the hydrocarbon fluid phase diagram obtained from the PVT experiment to verify the accuracy of the PVTsim software simulation, thus demonstrating the reliability of the subsequent fluid phase state prediction. The thermodynamic principle for determining whether a gas-liquid two-phase system is in equilibrium is that in a gas-liquid equilibrium system under the same pressure and temperature, the fugacity of each component in both the gas and liquid phases must be equal; that is: ; In the formula, , Let represent the fugacity of component i in the gas phase and liquid phase, respectively; the above formula is the criterion for determining whether a known system meets phase equilibrium, and can also be used to calculate the phase equilibrium ratio K; the calculation method is as follows: The fugacity of component i in the gas phase is equal to the product of the fugacity of pure component i in the gas phase and the mole fraction of component i in the gas phase under the same temperature and pressure system, that is: ; Similarly, the fugacity of component i in the liquid phase can be expressed as: ; In the formula, This represents the fugacity of pure component i in the gas phase at the system equilibrium temperature and pressure. This represents the fugacity of pure component i as a liquid phase at the system equilibrium temperature and pressure; 𝑦 i , i This indicates the mole fraction of component i in the gas phase and liquid phase; According to the equilibrium criterion, we get: ; Phase equilibrium ratio can be expressed in terms of fugacity, as shown below: ; In the formula, P is the equilibrium pressure of the system; Let be the liquid phase fugacity coefficient of component i; Let be the gas phase fugacity coefficient of component i; Calculate 𝐾 i At that time, a suitable equation of state is selected to calculate the fugacity coefficients φ of the gas and liquid phases respectively. i The formula for calculating the fugacity coefficient is: Gas phase: ; Liquid phase: ; in b i , b, a i 、a、 A and B are the parameters in the equation of state, and Z represents the gas-phase mixture. V The Z-value of the liquid mixture is the largest positive root of the cubic equation of state. L It is the smallest positive root of the cubic equation of state; Calculate the fugacity coefficients φ of the gas and liquid phases. iV , 𝛷 i𝐿 Given a system temperature T, pressure P, and mixture composition Z... j In this case, the phase equilibrium constant K is then determined. i value; Once the method for calculating the equilibrium ratio K is solved, the phase equations can be used to calculate the bubble point pressure, dew point pressure, and phase envelope. The phase equations for the gas-liquid system are as follows: Gas phase composition equation: ; Liquid phase composition equation: ; Bubble point pressure is the phase transition point at which a single-phase liquid in a closed system transforms into a two-phase system (gas and liquid). It can be understood as the pressure at which the system begins to release the first bubble. At the bubble point, the number of gas phases, n... g =0, number of liquid phases n L =n, using the gas phase composition equation, we have: Bubble point pressure calculation formula: ; The pressure in the formula is implied in K j In this context, given the system's composition and temperature, a trial pressure is assumed. If the K corresponding to the trial pressure... j If the above formula is satisfied, then this calculated pressure is the bubble point pressure; The dew point pressure is the phase transition point at which a system transforms from a single-phase gas to a two-phase system consisting of gas and liquid. L =0, n g =n, and using the liquid phase composition equation, we have: Dew point pressure calculation formula: ; The calculation method is the same as that for bubble point pressure. Based on the prediction of organic hydrocarbon generation products to determine the nC component composition in underground reservoir fluids at different evolution stages, PVT phase diagrams of underground reservoir fluids at different evolution stages are obtained through calculation and simulation using PVTsim software. Combined with the paleotemperature-pressure recovery of simulated geological history, the phase evolution of underground reservoir fluids at different stages and the current underground oil and gas phase state can be determined.

[0026] Example 3 A computer device includes a memory and a processor, the memory storing a computer program, and the processor executing the computer program to implement the steps of the method for predicting the phase state of deep underground oil and gas as described in Embodiment 1 or 2.

[0027] Example 4 A computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the steps of the method for predicting the phase state of deep underground oil and gas as described in Embodiment 1 or 2.

[0028] Example 5 A system for predicting the phase state of deep underground hydrocarbons includes: The deep temperature field recovery module is configured to: recover the deep temperature field of the study area based on the geothermal temperature of the study area; The deep pressure field recovery module is configured to: recover the deep pressure field of the study area; The fluid chemical composition determination module is configured to determine the fluid chemical composition of different geological periods in different strata. The oil and gas phase prediction module is configured to: input the fluid chemical composition and select the equation of state through PVTsim software, and generate a predicted PT phase diagram by combining the recovered deep temperature field and deep pressure field, thereby realizing the prediction of the phase state of deep underground oil and gas.

Claims

1. A method for predicting the phase state of deep underground oil and gas, characterized in that, include: Step 1: Reconstruct the deep temperature field of the study area based on the geothermal temperature of the study area; Step 2: Restore the deep pressure field of the study area; Step 3: Determine the fluid chemical composition of different geological periods in different strata; Step 4: Using PVTsim software, input the fluid chemical composition and select the equation of state. Combine the recovered deep temperature field and deep pressure field to generate the predicted PT phase diagram, thereby realizing the prediction of the phase state of deep underground oil and gas.

2. The method for predicting the phase state of deep underground oil and gas as described in claim 1, characterized in that, Based on the geothermal data of the study area, reconstruct the deep temperature field of the study area; including: Based on the current geothermal temperature of the study area, the heat flow history and geothermal history of the study area can be deduced, i.e., based on Easy- R o The model reconstructs the deep temperature field, including: Step 1.1: Reconstruct the stratigraphic history of the study area, that is, based on the seismic logging data of the study area, obtain the depth and formation time of the study area, and clarify the period of formation and current depth of the strata; Step 1.2: Setting the paleothermal flow Q0 represents the current hot trend. Indicates depth, Let t represent the unknown variable and t be time. The paleotemperature is calculated using the formula shown below: ； in, This represents the paleogeothermal temperature of the strata at a depth Z from the Earth's surface at a time t ago, where Ts is the surface temperature. Thermal conductivity at depth Z; Paleothermal temperature was measured and calibrated using the measured Ro (vitrinite reflectance). The θ value was adjusted so that the paleothermal temperature and the measured Ro satisfy the following relationship: ； Where n is the total number of measured Ro, This represents the measured Ro value at the k-th point. Represents the surface Ro value. This represents the measured Ro value at point j; This represents the time-temperature index at point k. Represents the time-temperature index at point j; where the time-temperature indexes of all points are... The calculation is as follows: ； Step 1.3: Compare the measured Ro with the paleogeothermal temperature. If the fit is good, that is, if the paleogeothermal temperature and the measured Ro satisfy the relationship... (k=1, 2, ..., n), then the paleogeothermal field is the actual geothermal history experienced by the strata, which is the deep temperature field; otherwise, repeat step 1.2 until the fitting degree is good.

3. The method for predicting the phase state of deep underground oil and gas as described in claim 2, characterized in that, Reconstruct the deep pressure field of the study area; including: By measuring the homogenization temperature, formation temperature, liquid salinity, and pressure at the time of fluid inclusion formation, and then using the relevant temperature-pressure relationship established by the saline solution to reconstruct the paleostress pressure during the hydrocarbon accumulation period in the study area, as shown below: ； ； ； Where P represents paleopressure, i.e., the pressure at which the inclusions formed, and T represents the ascent temperature, i.e., the temperature at which the inclusions formed. h The homogenization temperature is represented by , m represents the molality of the salt; a1, a2, a3, and a4 are constants for the liquid salt. The paleopressure P was calculated, which is the recovered deep pressure field of the study area.

4. The method for predicting the phase state of deep underground oil and gas as described in claim 3, characterized in that, Determine the fluid chemical composition of different geological periods in different strata; including: The process of generating hydrocarbons from organic matter is as follows: N It consists of a series of parallel first-order reactions, and each group has its own pre-exponential factor. Activation energy of reaction And set the initial hydrocarbon generation potential for each reaction as , i = 1, 2, ..., N ; in time t At that time, the first i The amount of hydrocarbons generated by each reaction is X i The reaction rates are shown below: ； ； in, Indicates the first i The reaction rate in each reaction, Represents the i-th pre-exponential factor. The pressure at which the gas is broken down into a gas. a This indicates the effect of pressure on the pre-exponential factor in hydrocarbon generation reactions. R It is the gas constant; Absolute temperature; Represents the activation energy of the i-th reaction. This represents the effect factor of pressure on activation energy in the i-th hydrocarbon generation reaction; uniform heating is used. The result is as follows: ； By integrating the above equation, we can calculate the first... i Hydrocarbon generation per reaction As shown below: ； in, T 0 Indicates the initial heating temperature; N The total hydrocarbon generation of the parallel reactions is shown below: ； in, X For all N Total hydrocarbon generation from a parallel reaction N The number of parallel first-order reactions; The total amount of oil produced by N parallel reactions of kerogen oil, XO, is shown below: ； in, This represents the amount of oil produced by the i-th reaction. Indicates the original oil-producing potential. This represents the pre-exponential factor of the i-th oil-generating reaction. This represents the activation energy of the i-th oil-generating reaction; The total amount of biogas generated in N parallel kerogen biogas reactions, XG, is shown below: ； in, This represents the amount of anger generated by the i-th reaction. Indicates the original potential of life force. This represents the pre-exponential factor of the i-th angry reaction. This represents the activation energy of the i-th gas-generating reaction; The total gas production (XOG) of N parallel oil cracking gas generation reactions is shown below: ； in, This represents the total amount of gas generated in the i-th parallel oil cracking gas generation reaction. This indicates the initial total gas production potential of the parallel reaction of oil cracking and gas generation. This represents the pre-exponential factor of the i-th parallel reaction of oil cracking and gas generation. This represents the activation energy of the i-th parallel reaction for gas generation from oil cracking; The NOO and TG of organic matter are shown below: ； ； The hydrogen generation thermal simulation experiment using gold tubes involves heating source rocks from different layers in the study area to simulate the underground hydrocarbon generation process, obtaining C1-C values ​​at different heating temperatures and times. n The maximum yield and percentage, where C1 is the first hydrocarbon, C n This is the nth hydrocarbon; Compare the NOO or TG production of oil with C1 to C2. n Multiply by the maximum yield to obtain the hydrocarbon production, i.e., the fluid chemical composition of different geological periods in different strata.

5. The method for predicting the phase state of deep underground oil and gas as described in claim 4, characterized in that, Using PVTsim software, the fluid chemical composition is input and the equation of state is selected. Combined with the recovered deep temperature and pressure fields, a predicted PT phase diagram is generated, enabling the prediction of the phase state of deep underground oil and gas. This includes: The state equation is either the PR state equation or the SRK state equation; The fluid chemical composition is input into the PVTsim software, and the PR equation of state or SRK equation of state is selected for calculation. The recovered deep temperature field and deep pressure field are also input to generate hydrocarbon PT phase diagrams in strata at different evolution stages. The fluid phase state is determined based on the hydrocarbon PT phase diagram, and thus the hydrocarbon phase state is predicted.

6. A computer device comprising a memory and a processor, wherein the memory stores a computer program, characterized in that, When the processor executes the computer program, it implements the steps of the method for predicting the phase state of deep underground oil and gas as described in any one of claims 1-7.

7. A computer-readable storage medium having a computer program stored thereon, characterized in that, When the computer program is executed by the processor, it implements the steps of the method for predicting the phase state of deep underground oil and gas as described in any one of claims 1-7.

8. A prediction system for the phase state of deep underground oil and gas, characterized in that, include: The deep temperature field recovery module is configured to: recover the deep temperature field of the study area based on the geothermal temperature of the study area; The deep pressure field recovery module is configured to: recover the deep pressure field of the study area; The fluid chemical composition determination module is configured to determine the fluid chemical composition of different geological periods in different strata. The oil and gas phase prediction module is configured to: input the fluid chemical composition and select the equation of state through PVTsim software, and generate a predicted PT phase diagram by combining the recovered deep temperature field and deep pressure field, thereby realizing the prediction of the phase of deep underground oil and gas.

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