Volcanic rock reservoir saturation calculation method based on basin simulation paleopressure recovery

Abstract

The invention discloses a volcanic rock reservoir saturation calculation method based on basin simulation paleo-pressure recovery, which comprises the following steps of: firstly, recovering paleo-pressure of hydrocarbon source rock in a target area by utilizing basin simulation and a fluid inclusion method, and calculating filling pressure of a reservoir in a reservoir forming period by combining hydrocarbon column buoyancy of an oil and gas reservoir and hydrostatic pressure of a stratum; then oil (gas) saturation of each capillary pressure sample is determined by using a filling pressure and core mercury injection experiment, and a nuclear magnetic resonance logging T2 cut-off value is calibrated; and finally, the oil (gas) saturation of the whole well section is calculated by using the calibrated nuclear magnetic resonance logging information. According to the method, the combined action of buoyancy filling and source rock overpressure in the volcanic rock reservoir formation process is comprehensively considered and used for mercury injection experiment data analysis, nuclear magnetic resonance logging information is calibrated through the core mercury injection experiment result to achieve reservoir saturation calculation, and the saturation evaluation accuracy of the volcanic rock reservoir is effectively improved.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil and gas exploration and development, and particularly relates to a method for calculating the saturation of volcanic rock reservoirs based on the restoration of paleo-pressure by basin simulation. Background Art

[0002] The oil (gas) saturation, as a key parameter for reservoir logging evaluation, is an important reference basis for dividing the effective thickness of reservoirs, and plays an important guiding role in exploration reserve evaluation and development production plans. In conventional clastic reservoirs, the lithology is usually relatively single, the pore structure is mainly intergranular pores, and the reservoir pressure conditions are relatively simple. After oil and gas are generated in the source rock, they migrate and accumulate to the reservoir to form reservoirs through buoyancy. The degree of oil and gas filling, that is, the oil (gas) saturation, is mainly controlled by the buoyancy formed by the hydrocarbon column height and has a quantitative relationship. The saturation under the condition of single-buoyancy accumulation can be calibrated through mercury injection experiments on cores. On the other hand, there is a quantitative relationship between the oil (gas) saturation and the electrical properties of the reservoir. By obtaining the rock electrical parameters under the formation temperature and pressure conditions through experiments and then substituting them into Archie's formula or its deformed form, the oil (gas) saturation of the entire well section can be calculated. At present, in China, for conventional clastic reservoirs and single-lithology volcanic rock reservoirs mainly with pore types, Archie's formula and its deformed forms are often used to calculate the oil (gas) saturation, and then calibrated through mercury injection experiment data to achieve accurate evaluation of reservoir saturation.

[0003] However, most volcanic rock reservoirs have experienced multiple eruptions. Taking the Mesozoic volcanic rock reservoirs in the Bohai Sea of China as an example, their lithology changes rapidly, and dissolution pores, microfractures and primary matrix pores coexist in the reservoirs; and the accumulation mode is complex. A large number of mercury injection experiment statistics and regional paleo-pressure and current pressure analyses show that there is an overpressure accumulation background. On the one hand, these characteristics make the single-buoyancy accumulation mode unable to meet the calibration of oil (gas) saturation under overpressure injection conditions. On the other hand, the complex lithology and pore structure bring great difficulties to the determination of rock electrical parameters, and there are large errors in calculating the oil (gas) saturation by the existing Archie's formula or the hydrocarbon column height method based on core mercury injection. Nuclear magnetic resonance logging is a new method for evaluating the saturation of complex reservoirs widely used in recent years. It measures the T2 spectrum (relaxation time spectrum) at different depth points. Since fluid molecules have different relaxation times due to the difference in hydrogen nuclei, by determining the T2 cut-off value through core nuclear magnetic resonance experiments and using it as the calibration value of the T2 spectrum, the oil (gas) saturation can be obtained. However, the centrifugal pressure of the nuclear magnetic resonance experiment is small and far from reaching the overpressure injection conditions, so the T2 cut-off value of nuclear magnetic resonance logging cannot be accurately calibrated, affecting the calculation accuracy of the oil (gas) saturation. Summary of the Invention

[0004] The present invention is proposed to solve the problems existing in the prior art, and its purpose is to provide a method for calculating the saturation of volcanic rock reservoirs based on the restoration of paleo-pressure by basin simulation.

[0005] The present invention is achieved through the following technical solutions:

[0006] A method for calculating the saturation of volcanic rock reservoirs based on the restoration of paleopressure by basin simulation, comprising the following steps:

[0007] S1. Use basin simulation and fluid inclusion methods to restore the paleopressure P of the source rock in the target area a ;

[0008] Based on seismic, geological, and drilling and logging data, establish a geological model of the hydrocarbon-generating sag and the bulge structure where the oil and gas reservoir is located, carry out basin simulation to restore the pressure evolution and oil and gas migration and accumulation processes of the entire geological model, and restore the paleopressure P of the source rock during the reservoir formation period through fluid inclusion analysis a And perform correction on the simulation results;

[0009] S2. Calculate the hydrocarbon column buoyancy of the oil and gas reservoir and the corresponding formation hydrostatic pressure, and combine the paleopressure of the source rock in step S1 to calculate the injection pressure of the reservoir during the formation period, specifically including the following steps:

[0010] S21. Assume that the original formation pressure of the reservoir during the formation period is normal pressure, and the formation pressure P p is approximately equal to the hydrostatic pressure P hyd , and the calculation formula for the hydrostatic pressure P hyd is:

[0011] P p ≈P hyd =ρ w gh…………(1)

[0012] In the formula: P p is the formation pressure, with the unit of Pa; P hyd is the hydrostatic pressure, with the unit of Pa; h is the reservoir burial depth, with the unit of m; ρ w is the formation water density, kg / m 3 ; g is the acceleration of gravity, with the unit of kg·m / s 2 ;

[0013] S22. During the relatively short reservoir formation period, the loss of paleopressure conduction of the source rock along the fault can be ignored. Therefore, the overpressure P transmitted from the source rock to the reservoir can be calculated using the geological model and the paleopressure P of the source rock in step S1 a and the hydrostatic pressure P obtained in step S21 hyd ; t ;

[0014] The calculation formula for the overpressure P transmitted from the source rock to the reservoir t is:

[0015] P t =P a -Phyd …………(2)

[0016] Where: P t is the overpressure transferred from the source rock to the reservoir, in Pa; P a is the paleo-pressure of the source rock, in Pa; P hyd is the hydrostatic pressure, in Pa;

[0017] S23. The hydrocarbon column buoyancy P of the oil and gas reservoir b is formed by the density difference between the oil and gas and water. The calculation formula for the hydrocarbon column buoyancy P of the oil and gas reservoir b is:

[0018]

[0019] Where: P b is the hydrocarbon column buoyancy, in Pa; ρ w is the density of formation water, in kg / m 3 ; ρ o is the density of crude oil under formation conditions, in kg / m 3 ; ρ g is the density of gas under formation conditions, in kg / m 3 ; g is the acceleration of gravity, in kg·m / s 2 ; h o is the height of the oil column, in m; h g is the height of the gas column, in m;

[0020] S24. Using the hydrocarbon column buoyancy P of the oil and gas reservoir b , combined with the overpressure P transferred from the source rock to the reservoir t to approximately obtain the injection pressure P of the reservoir during the hydrocarbon accumulation period chg . The calculation formula for the injection pressure of the reservoir during the hydrocarbon accumulation period is:

[0021] P chg = P b + P t …………(4)

[0022] Where: P chg is the injection pressure of the reservoir during the hydrocarbon accumulation period, in Pa; P b is the hydrocarbon column buoyancy, in Pa; P t is the overpressure transferred from the source rock to the reservoir, in Pa;

[0023] S3. Based on the injection pressure P of the reservoir during the hydrocarbon accumulation period obtained by step S2 chg , determine the oil (gas) saturation S of each core capillary pressure sample under the condition of hydrocarbon overpressure accumulation hc , specifically including the following steps:

[0024] S31. Convert the injection pressure P obtained in step S2 chg into the mercury injection pressure P for the core capillary pressure experiment through the mercury-air system and the oil (gas)-water system relationship Hg . The calculation formula for the mercury injection pressure is as follows:

[0025]

[0026] In the formula: P Hg is the mercury injection pressure for the core capillary pressure experiment, with the unit of Pa; P chg is the injection pressure of the reservoir during the hydrocarbon accumulation period, with the unit of Pa;

[0027] S32. Determine the mercury injection saturation S Hg on the mercury injection curve in the high-pressure mercury injection experiment based on the mercury injection pressure P obtained in step S31 Hg . The mercury injection saturation S Hg is equivalent to the oil (gas) saturation S under formation conditions hc ;

[0028] S4. Calibrate the T2 cut-off value of nuclear magnetic resonance logging using the oil (gas) saturation S of the core capillary pressure determined in step S3, and then calculate the oil (gas) saturation of the entire well section using nuclear magnetic resonance logging. The specific steps are as follows: hc S41. Measure the T2 spectrum (relaxation time spectrum) at different depth points by nuclear magnetic resonance logging. Using the T2 cut-off value as the boundary value, the bound fluid and movable fluid can be divided to obtain the nuclear magnetic movable fluid porosity and effective porosity of the volcanic rock reservoir, and then calculate the irreducible water saturation of the volcanic rock reservoir;

[0029] The calculation formula for the irreducible water saturation of the volcanic rock reservoir is:

[0030] In the formula: S

[0031]

[0032] is the nuclear magnetic calculated capillary irreducible water saturation, with the unit of f; S1 is the area of the T2 spectrum of the capillary irreducible water signal measured by nuclear magnetic resonance logging, with the unit of f; S is the total area of the T2 spectrum measured by nuclear magnetic resonance logging, with the unit of f; T2 is the nuclear magnetic resonance measurement time, with the unit of ms; T wi is the maximum T2 value measured by the nuclear magnetic resonance logging instrument, with the unit of ms; T 2max is the T2 cut-off value of the capillary irreducible water, with the unit of ms; 2cutoff NMR

[0033] S42. Calculate the movable oil and gas saturation S NMR from nuclear magnetic resonance logging. The calculation formula for the movable oil and gas saturation S NMR is:

[0034] S NMR = 1 - S wi …………(7)

[0035] In the formula: S NMR is the movable oil and gas saturation calculated by nuclear magnetic resonance logging, with the unit of f; S wi is the capillary bound water saturation calculated by nuclear magnetic resonance, with the unit of f;

[0036] S43. Using the oil (gas) saturation S hc obtained at different sampling points in step S3 and the movable oil and gas saturation S NMR calculated by nuclear magnetic resonance logging to construct an objective function, set the value range of the T2 cut-off value, and traverse to obtain the T2 cut-off value. The expression of the objective function is:

[0037] F = ∑[S hc - S NMR (T 2cutoff )] 2 …………(8)

[0038] In the formula: F is the objective function, taking the minimum value, dimensionless; S hc is the oil (gas) saturation under formation conditions, with the unit of f; S NMR is the movable oil and gas saturation calculated by nuclear magnetic resonance logging, with the unit of f; T 2cutoff is the calibration value of nuclear magnetic resonance logging, with the unit of ms;

[0039] S44. Take the geometric mean T 2geo of the T2 cut-off values obtained for all core sampling depth points. Use the geometric mean T 2geo as the calibration value T 2cutoff of nuclear magnetic resonance logging and substitute it into formula 6 to calculate the bound water saturation of the volcanic rock reservoir, and then calculate the oil (gas) saturation of the entire well section through the nuclear magnetic movable oil and gas saturation calculation formula 7.

[0040] The beneficial effects of the present invention are:

[0041] The present invention provides a method for calculating the saturation of volcanic rock reservoirs based on the restoration of paleopressure by basin simulation. In volcanic rock reservoirs with rapid lithological changes, where dissolved pores, microfractures and primary matrix pores coexist in the reservoir, and with a complex hydrocarbon accumulation pattern and an overpressure hydrocarbon accumulation background, the basin simulation and fluid inclusion methods are used to restore the injection pressure during the hydrocarbon accumulation period. The injection pressure is used to analyze the mercury injection experiment data of core samples and calibrate the T2 cut-off value of nuclear magnetic resonance logging, thereby realizing the calculation of the saturation of nuclear magnetic resonance logging in the reservoir. The present invention comprehensively considers the combined effects of buoyancy injection and source rock overpressure during the hydrocarbon accumulation process of volcanic rock reservoirs and applies them to the analysis of mercury injection experiment data, and realizes the calculation of reservoir saturation by calibrating nuclear magnetic resonance logging data with the results of core mercury injection experiments, effectively improving the accuracy of saturation evaluation of volcanic rock reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0042] Figure 1 is the flowchart of the method of the present invention;

[0043] Figure 2 is the schematic diagram of injection pressure calculation based on the restoration of paleopressure by basin simulation in Embodiment 1 of the present invention;

[0044] Figure 3 is the mercury injection curve when determining the mercury injection saturation of the mercury injection experiment using the injection pressure in Embodiment 1 of the present invention;

[0045] Figure 4 is the comprehensive result diagram of Embodiment 1 of the present invention.

[0046] For those of ordinary skill in the art, without creative efforts, other related drawings can be obtained based on the above drawings. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0047] In order to enable those skilled in the art of the present technology to better understand the technical solutions of the present invention, the technical solutions of the present invention will be further described below with reference to the accompanying drawings of the specification and through specific embodiments.

[0048] Embodiment 1

[0049] As Figure 1 shown, a method for calculating the saturation of volcanic rock reservoirs based on the restoration of paleopressure by basin simulation includes the following steps:

[0050] S1. Use the basin simulation and fluid inclusion methods to restore the paleopressure of the source rock in the target area

[0051] Based on seismic, geological, drilling and logging data, a two-dimensional cross-sectional geological model of the over-mature hydrocarbon generation sags A and B and the C uplift where the target oil and gas reservoir (the target interval of Well X) is located is established. Basin simulation is carried out to restore the pressure evolution and the process of oil and gas migration and accumulation of the entire geological model. Fluid inclusion analysis is carried out on the core samples of the oil and gas showing intervals in the Mesozoic reservoirs of the target interval of Well X to restore the paleo-fluid pressure value during the hydrocarbon accumulation period, and this paleo-fluid pressure value is used to continuously correct the simulation process to obtain a simulation result that conforms to the actual geological conditions. The results show that the mudstone hydrocarbon source rocks in Sag A and Sag B formed overpressure hydrocarbon fluids during the hydrocarbon accumulation period, and the paleo-pressure of the hydrocarbon source rocks was P a , and migrated along the carrier bed to the reservoirs in the C uplift, and were charged and accumulated under the combined action of oil and gas buoyancy and transmitted overpressure (see Figure 2 ).

[0052] S2. Calculate the buoyancy of the hydrocarbon column in the oil and gas reservoir and the corresponding formation hydrostatic pressure, and calculate the charging pressure of the reservoir during the hydrocarbon accumulation period in combination with the paleo-pressure of the hydrocarbon source rock in step S1;

[0053] S21. Assume that the original formation pressure of the reservoir during the hydrocarbon accumulation period is normal pressure, then the formation pressure is approximately equal to the hydrostatic pressure, and it is calculated by Equation (1):

[0054] P p ≈P hyd =ρ w gh…………(1)

[0055] In the formula: P p is the formation pressure, with the unit of Pa; P hyd is the hydrostatic pressure, with the unit of Pa; h is the reservoir burial depth, with the unit of m; ρ w is the formation water density, kg / m 3 ; g is the acceleration of gravity, with the unit of kg·m / s 2 ;

[0056] The burial depth of the Mesozoic reservoir of Well X is about 4000 m, and the formation water density is taken as 1000 kg / m 3 , and using Equation (1), P p ≈P hyd =40 MPa.

[0057] S22. During the relatively short hydrocarbon accumulation period, the loss of the paleo-pressure of the hydrocarbon source rock conducted along the fault can be ignored. Therefore, the overpressure amount P a transmitted from the hydrocarbon source rock to the reservoir can be calculated using the geological model and the paleo-pressure P hyd of the hydrocarbon source rock in step S1 and the hydrostatic pressure P t ;

[0058] P t =P a -P hyd …………(2)

[0059] In the formula: P t is the amount of overpressure transferred from the source rock to the reservoir, with the unit of Pa; P a is the paleo-pressure of the source rock, with the unit of Pa; P hyd is the hydrostatic pressure, with the unit of Pa;

[0060] S23. The hydrocarbon column buoyancy P of the oil and gas reservoir b is formed by the density difference between the oil and gas and water. The hydrocarbon column buoyancy P of the oil and gas reservoir b has the following calculation formula:

[0061]

[0062] In the formula: P b is the hydrocarbon column buoyancy, with the unit of Pa; ρ w is the density of formation water, with the unit of kg / m 3 ; ρ o is the density of crude oil under formation conditions, with the unit of kg / m 3 ; ρ g is the density of gas under formation conditions, with the unit of kg / m 3 ; g is the acceleration of gravity, with the unit of kg·m / s 2 ; h o is the height of the oil column, with the unit of m; h g is the height of the gas column, with the unit of m;

[0063] In Well X, a set of condensate gas reservoirs are developed in the Mesozoic. The height of the gas column is about 300 m, and the density of the condensate gas in the PVT sample is about 650 kg / m 3 , and the buoyancy corresponding to the top of the gas reservoir is about 1 MPa obtained by using Equation (3);

[0064] S24. Using the hydrocarbon column buoyancy P of the oil and gas reservoir in Well X b , and combining with the amount of overpressure P t transferred from the source rock to the reservoir in Step S1, approximately obtain the injection pressure P chg of the reservoir during the hydrocarbon accumulation period. The calculation formula for the injection pressure of the reservoir during the hydrocarbon accumulation period is:

[0065] P chg = P b + P t …………(4)

[0066] In the formula: P chg is the injection pressure of the reservoir during the hydrocarbon accumulation period, with the unit of Pa; P b is the hydrocarbon column buoyancy, with the unit of Pa; P t is the amount of overpressure transferred from the source rock to the reservoir, with the unit of Pa;

[0067] The injection pressure P of Well X is calculated by Equation (4) chg≈70 MPa, such as Figure 2 shown by the red arrow in the reservoir.

[0068] S3. Determine the oil (gas) saturation of each core capillary pressure experiment under the overpressure hydrocarbon accumulation condition according to the injection pressure calculated in step S2;

[0069] S31. Since the Mesozoic in Well X is a condensate gas reservoir, the injection pressure P of the reservoir during the hydrocarbon accumulation period is converted into the mercury injection pressure P of the core mercury injection experiment by using the conversion formula of the gas reservoir part in Equation (5) chg ; Hg ;

[0070]

[0071] In the formula: P Hg is the mercury injection pressure of the core capillary pressure experiment, with the unit of Pa; P chg is the injection pressure of the reservoir during the hydrocarbon accumulation period, with the unit of Pa;

[0072] S32. Then, determine the mercury injection saturation S of the sample with the mercury injection pressure P of the core mercury injection experiment Hg( (see Hg ), at this time, S Figure 3 is equal to the gas saturation S at the sampling point under formation conditions. The gas saturation of the core wall sampling point in Well X determined by this method is shown in Hg the 10th black bar chart. For comparison, the gas saturation of the sampling point determined by using single buoyancy injection is shown in hc the 8th gray bar chart. Figure 4 ; Figure 4 ;

[0073] S4. Calibrate the NMR logging T2 cut-off value with the core capillary pressure oil saturation determined in step S3, and then calculate the oil (gas) saturation of the whole well section by using NMR logging

[0074] S41. The NMR logging measures the T2 spectrum (relaxation time spectrum) at different depth points. Using the T2 cut-off value as the boundary value, the bound fluid and movable fluid can be divided to obtain the nuclear magnetic movable fluid porosity and effective porosity of the volcanic rock reservoir, and then calculate the irreducible water saturation of the volcanic rock reservoir;

[0075] The calculation formula for the irreducible water saturation of the volcanic rock reservoir is:

[0076]

[0077] In the formula: S wiFor calculating the capillary bound water saturation by nuclear magnetic resonance, the unit is f; S1 is the area of the capillary bound water signal T2 spectrum measured by nuclear magnetic resonance logging, the unit is f; S is the total area of the T2 spectrum measured by nuclear magnetic resonance logging, the unit is f; T2 is the nuclear magnetic resonance measurement time, the unit is ms; T 2max is the maximum value of T2 measured by the nuclear magnetic resonance logging instrument, the unit is ms; T 2cutoff is the T2 cut-off value of the capillary bound water, the unit is ms;

[0078] S42. Calculate the movable oil and gas saturation S NMR by nuclear magnetic resonance logging. The movable oil and gas saturation S NMR is calculated by the following formula:

[0079] S NMR = 1 - S wi …………(7)

[0080] In the formula: S NMR is the movable oil and gas saturation calculated by nuclear magnetic resonance logging, the unit is f; S wi is the capillary bound water saturation calculated by nuclear magnetic resonance, the unit is f;

[0081] S43. Use the oil (gas) saturation S hc obtained at different sampling points in step S3 and the movable oil and gas saturation S NMR calculated by nuclear magnetic resonance logging of Well X to construct an objective function, set the value range of the T2 cut-off value, and traverse to obtain the T2 cut-off value. The expression of the objective function is:

[0082] F = ∑[S hc - S NMR (T 2cutoff )] 2 …………(8)

[0083] In the formula: F is the objective function, taking the minimum value, dimensionless; S hc is the oil (gas) saturation under formation conditions, the unit is f; S NMR is the movable oil and gas saturation calculated by nuclear magnetic resonance logging, the unit is f; T 2cutoff is the calibration value of nuclear magnetic resonance logging, the unit is ms;

[0084] S44. Take the geometric mean T 2geo of the T2 cut-off values obtained at all core sampling depth points of Well X. T 2geo ≈ 10 ms( Figure 4 Figure 9 is the T2 spectrum of nuclear magnetic resonance logging, and the black solid line is T 2geo ), use T 2geo as the calibration value of nuclear magnetic resonance logging for the reservoir section, and use equations (6) and (7) to calculate the oil (gas) saturation of the reservoir. The calculation results are as followsFigure 4 As shown by the 10th red solid line. The hydrocarbon saturation calculated by nuclear magnetic resonance logging has a good consistency with the saturation determined by mercury injection experiment based on the charging pressure of source rocks, verifying the reliability of this method; at the same time, compared with the gas saturation calculated by the hydrocarbon column height method under the condition of single buoyancy charging, it has increased by about 25%, greatly improving the accuracy of volcanic reservoir saturation evaluation.

[0085] The logging evaluation method for volcanic reservoir saturation based on paleo-pressure restoration by basin simulation provided by the present invention, in volcanic reservoirs with rapid lithological changes, coexistence of dissolved pores, microfractures and primary matrix pores in the reservoir, and complex hydrocarbon accumulation patterns and overpressure hydrocarbon accumulation backgrounds, uses basin simulation and fluid inclusion methods to restore the original overpressure charging pressure during the hydrocarbon accumulation period, analyzes the core mercury injection experiment data with the overpressure charging pressure and uses it to calibrate the T2 cut-off value of nuclear magnetic resonance logging, and then realizes the calculation of nuclear magnetic resonance logging saturation of the reservoir. This method comprehensively considers the combined action of buoyancy and overpressure, and greatly improves the calculation accuracy of volcanic reservoir saturation compared with traditional methods.

[0086] The applicant declares that the above is only the specific implementation manner of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily thought of by those skilled in the art within the technical scope disclosed by the present invention fall within the protection scope and public scope of the present invention.

Claims

1. A method for calculating the saturation of volcanic rock reservoirs based on the restoration of paleopressure by basin simulation, characterized in that: It includes the following steps: S1. Use basin simulation and fluid inclusion methods to restore the paleopressure P of the source rocks in the target area a ; S2. Calculate the buoyancy of the hydrocarbon column in the oil and gas reservoir and the corresponding formation hydrostatic pressure, and combine the paleo-pressure of the source rock in step S1 to calculate the injection pressure of the reservoir during the hydrocarbon accumulation period: S3. The injection pressure P of the reservoir during the hydrocarbon accumulation period obtained through step S2 chg , to determine the oil (gas) saturation S of each core capillary pressure sample under the condition of hydrocarbon overpressure accumulation hc ; S4. Oil (gas) saturation S of the core capillary pressure determined through step S3 hc Calibrate the nuclear magnetic resonance logging T2 cut-off value, and then use the nuclear magnetic resonance logging to calculate the oil (gas) saturation of the entire well section.

2. The method for calculating the saturation of volcanic rock reservoirs based on the restoration of paleo-pressure by basin simulation according to claim 1, wherein: The specific steps of step S1 are as follows: Based on seismic, geological, drilling and logging data, a geological model of the hydrocarbon generation sag and the convex structure where the oil and gas reservoir is located is established, basin simulation is carried out to restore the pressure evolution and the process of oil and gas migration and accumulation of the entire geological model, and the paleo-pressure P of the source rock during the reservoir formation period is restored through fluid inclusion analysis a And the simulation results are corrected.

3. The method for calculating the saturation of volcanic rock reservoirs based on paleopressure restoration by basin simulation according to claim 1, wherein: The specific steps of step S2 include the following steps: S21. Assume that the original formation pressure of the reservoir during hydrocarbon accumulation is normal pressure, and the formation pressure P p is approximately equal to the hydrostatic pressure P hyd . The calculation formula for the hydrostatic pressure P hyd is as follows: P p ≈P hyd =ρ w gh…………(1) Where: P p is the formation pressure, in Pa; P hyd is the hydrostatic pressure, in Pa; h is the reservoir burial depth, in m; ρ w is the formation water density, in kg / m 3 ; g is the acceleration of gravity, in kg·m / s 2 ; S22. Use the geological model in step S1 and the paleo-pressure P of the source rock a and the hydrostatic pressure P obtained in step S21 hyd to calculate the overpressure P transferred from the source rock to the reservoir t ; The overpressure amount P transferred from the hydrocarbon source rock to the reservoir t is calculated by the formula: P t = P a -P hyd …………(2) where: P t is the amount of overpressure transferred from the source rock to the reservoir, in Pa; P a is the paleo-pressure of the source rock, in Pa; P hyd is the hydrostatic pressure, in Pa; S23. Hydrocarbon column buoyancy P of the hydrocarbon reservoir b Formed by the density difference between hydrocarbons and water, the hydrocarbon column buoyancy P of the hydrocarbon reservoir b The calculation formula is as follows: Where: P b is the buoyancy of the hydrocarbon column, with the unit of Pa; ρ w is the density of formation water, with the unit of kg / m 3 ; ρ o is the density of crude oil under formation conditions, with the unit of kg / m 3 ; ρ g is the density of gas under formation conditions, with the unit of kg / m 3 ; g is the acceleration of gravity, with the unit of kg·m / s 2 ; h o is the height of the oil column, with the unit of m; h g is the height of the gas column, with the unit of m; S24. Utilize the hydrocarbon column buoyancy P of the hydrocarbon reservoir b , and combine it with the overpressure amount P transferred from the source rock to the reservoir t to approximately obtain the injection pressure P of the reservoir during the hydrocarbon accumulation period chg . The calculation formula for the injection pressure of the reservoir during the hydrocarbon accumulation period is as follows: P chg = P b + P t …………(4) Where: P chg is the injection pressure of the reservoir during hydrocarbon accumulation, with the unit of Pa; P b is the buoyancy of the hydrocarbon column, with the unit of Pa; P t is the amount of overpressure transferred from the source rock to the reservoir, with the unit of Pa.

4. The method for calculating the saturation of volcanic rock reservoirs based on paleopressure restoration by basin simulation according to claim 1, characterized in that: The specific steps of step S3 include the following steps: S31. Convert the charging pressure P obtained in step S2 chg into the mercury injection pressure P for the core capillary pressure experiment through the mercury-air system and the oil (gas)-water system relationship. Hg The calculation formula for the mercury injection pressure is as follows: Where: P Hg is the mercury injection pressure in the core capillary pressure experiment, with the unit of Pa; P chg is the injection pressure of the reservoir during the hydrocarbon accumulation period, with the unit of Pa; S32. The mercury injection pressure P obtained through step S31 Hg Determine the mercury injection saturation S on the mercury injection curve of the high-pressure mercury injection experiment Hg , the mercury injection saturation S Hg is equivalent to the oil (gas) saturation S under formation conditions hc .

5. The method for calculating the saturation of volcanic rock reservoirs based on paleopressure restoration by basin simulation according to claim 1, wherein: The specific steps of step S4 include the following steps: S41. Use nuclear magnetic resonance logging to measure the T2 spectra at different depth points, divide the bound fluid and the movable fluid with the T2 cut-off value as the boundary value, obtain the nuclear magnetic movable fluid porosity and the effective porosity of the volcanic rock reservoir, and then calculate the irreducible water saturation of the volcanic rock reservoir; The calculation formula for the irreducible water saturation of the volcanic rock reservoir is: Where: S wi is the capillary bound water saturation calculated by nuclear magnetic resonance, with the unit of f; S1 is the area of the T2 spectrum of the capillary bound water signal measured by nuclear magnetic resonance logging, with the unit of f; S is the total area of the T2 spectrum measured by nuclear magnetic resonance logging, with the unit of f; T2 is the nuclear magnetic resonance measurement time, with the unit of ms; T 2max is the maximum value of T2 measured by the nuclear magnetic resonance logging tool, with the unit of ms; T 2cutoff is the T2 cut-off value of the capillary bound water, with the unit of ms; S42. Calculating the movable oil-gas saturation S from nuclear magnetic resonance logging NMR , where the movable oil-gas saturation S NMR is calculated by the following formula: S NMR = 1 - S wi …………(7) Where: S NMR is the movable oil and gas saturation calculated by nuclear magnetic resonance logging, with the unit of f; S wi is the capillary bound water saturation calculated by nuclear magnetic resonance, with the unit of f; S43. Utilize the oil (gas) saturation S at different sampling points obtained in step S3 hc and the movable oil and gas saturation S calculated by nuclear magnetic resonance logging NMR to construct an objective function, set the value range of the T2 cut-off value, and traverse to obtain the T2 cut-off value. The expression of the objective function is as follows: F = ∑[S hc - S NMR (T 2cutoff )] 2 …………(8) In the formula: F is the objective function, taking the minimum value, dimensionless; S hc is the oil (gas) saturation under formation conditions, with the unit of f; S NMR is the movable oil and gas saturation calculated by nuclear magnetic resonance logging, with the unit of f; T 2cutoff is the calibration value of nuclear magnetic resonance logging, with the unit of ms; S44. Obtain the geometric mean value T of the T2 cut-off values for all core sampling depth points 2geo , and use the geometric mean value T 2geo as the calibration value T for nuclear magnetic resonance logging 2cutoff Substitute it into the calculation formula of the irreducible water saturation of volcanic rock reservoirs to calculate the irreducible water saturation of volcanic rock reservoirs, and then use the calculation formula of the movable oil and gas saturation S NMR to calculate the oil (gas) saturation of the entire well section.

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