Ultra-shallow natural gas hydrate-free gas coexistence zone saturation calculation method and computer equipment

Abstract

The invention relates to an ultra-shallow natural gas hydrate-free gas coexistence zone saturation calculation method, which comprises the following steps: acquiring nuclear magnetic resonance logging one-dimensional continuous measurement T2 spectrum data and two-dimensional spot measurement mode data to obtain a time-diffusion coefficient distribution spectrum; performing water and gas signal identification according to the time-diffusion coefficient distribution spectrum to calculate water saturation and free gas saturation; carrying out hydrocarbon-containing correction on the nuclear magnetic spot measurement porosity to obtain the real nuclear magnetic spot measurement total porosity of the stratum; the method comprises the following steps: acquiring conventional logging curve data, establishing a rock physical volume model of a hydrate-free gas coexistence zone and a comprehensive logging response equation set, and taking the total porosity measured by a real nuclear magnetic spot of a stratum as calibration data for optimal solution; and solving the rock skeleton mineral component and the pore fluid component to obtain the coexisting zone hydrate saturation, the free gas saturation and the formation water saturation. According to the method, the problem of low calculation precision of the gas saturation and the hydrate saturation of the hydrate-shallow gas coexisting zone reservoir is solved.

Description

Technical Field

[0001] The present invention relates to the technical field of petroleum and natural gas hydrate and shallow gas exploration, and more specifically, to a method and computer equipment for calculating the saturation of an ultra-shallow natural gas hydrate-free gas coexistence zone. Background Art

[0002] As the global demand for natural gas continues to increase, natural gas hydrates and shallow gas have become one of the key targets of offshore oil and gas exploration. Offshore oil and gas exploration practices have shown that there is a coexistence zone of hydrates and natural gas in deepwater ultra-shallow gas reservoirs, and the saturation of hydrates and shallow gas is a key parameter for reserve calculation, which is of great significance to the development of hydrates and shallow gas.

[0003] At present, the methods for quantitatively evaluating the saturation of hydrate and shallow gas coexistence zones using well logging curves mainly include the resistivity model method, the acoustic velocity model method and the combination of nuclear magnetic resonance and density. The disadvantage of the resistivity model method is that both hydrate and shallow gas belong to high-resistance layers, and the saturation of the two cannot be distinguished; the disadvantage of the acoustic velocity model method is that the acoustic wave is greatly affected by the gas content, and the higher the gas saturation, the greater the impact on the acoustic velocity; in addition, the presence of hydrates will strengthen the cementation of rock skeleton particles, resulting in an increase in acoustic velocity, and the choice of acoustic velocity rock physics model depends on the occurrence state of hydrates, so the saturation calculated using acoustic logging usually has a large error. The main disadvantages of the conventional NMR-density combined method include two aspects: first, the movable fluid in the paragenetic zone contains free gas, and the NMR porosity is greatly affected by hydrocarbon content. The existing method does not perform hydrogen correction. At this time, the NMR porosity is not the formation fluid porosity; second, when establishing the density volume model, the skeleton density and fluid density are regarded as constants, while the actual formation rock skeleton density and fluid density will vary greatly due to changes in mineral components and fluid components. At this time, the total porosity obtained by density logging is not the true total porosity of the formation; the above two disadvantages combined lead to large errors in the calculation results of this method. Summary of the invention

[0004] In order to overcome the problem of large calculation error in the above-mentioned prior art method of quantitatively evaluating the saturation of hydrate and shallow gas coexistence zone using well logging curves, the present invention provides a method for calculating the saturation of ultra-shallow natural gas hydrate-free gas coexistence zone.

[0005] In order to solve the above technical problems, the technical solution adopted by the present invention is: a method for calculating the saturation of an ultra-shallow natural gas hydrate-free gas coexistence zone, comprising the following steps:

[0006] S1, obtaining one-dimensional continuous measurement T2 spectrum data and two-dimensional point measurement mode data of nuclear magnetic resonance logging, and inverting the two-dimensional point measurement mode data to obtain a transverse relaxation time-diffusion coefficient distribution spectrum, identifying water and gas signals according to the transverse relaxation time-diffusion coefficient distribution spectrum, calculating the water volume and free gas volume according to the identification signals, and respectively calculating the water saturation and the free gas saturation according to the water volume and the free gas volume;

[0007] S2. Based on the calculated water saturation and free gas saturation, the nuclear magnetic point-measured porosity is corrected for hydrocarbons to obtain the true nuclear magnetic point-measured total porosity of the formation that is not affected by gas content;

[0008] S3. Acquire conventional logging curve data, establish a rock physical volume model of the hydrate-free gas coexistence zone, establish a comprehensive logging response equation group, use the real nuclear magnetic point measured total porosity of the formation as the calibration data for optimizing the solution of the comprehensive logging response equation group, and use the optimal inversion method to solve the rock skeleton mineral composition and pore fluid composition to obtain the hydrate saturation, free gas saturation and formation water saturation of the coexistence zone.

[0009] Preferably, in step S1, in a two-dimensional point measurement mode, multiple CPMG sequences are measured using different waiting times WT and echo intervals T E , collect multiple sets of echo train data, perform two-dimensional inversion on the echo train data to obtain transverse relaxation time-diffusion coefficient spectrum;

[0010]

[0011] In the formula, b(t,T E ) is the echo amplitude, f(T2,D) is the two-dimensional distribution function about the two parameters T2 and D; γ is the gyromagnetic ratio; G is the fixed magnetic field gradient; D is the diffusion coefficient of the fluid; T E is the echo interval; ε is the noise.

[0012] Preferably, in step S2, the formula for performing hydrocarbon correction on the nuclear magnetic point porosity is as follows:

[0013]

[0014] In the formula, φ cor is the corrected total porosity measured by nuclear magnetic field, i.e. the actual total porosity measured by nuclear magnetic field; φ MRF HI is the total porosity measured by NMR before correction; g HI is the hydrogen index of natural gas; w is the hydrogen content index of water; S w ' is water saturation; S gxo ' is the free gas saturation.

[0015] Preferably, in step S3, establishing a rock physical volume model of the hydrate-free gas coexistence zone includes:

[0016] For the rock skeleton and clay parts, the mineral types were determined by the quantitative analysis of the whole-rock X-ray diffraction of the core. The volumes of the skeleton and clay parts are V and V respectively. ma 、V sh ;

[0017] Regarding the pore fluid components, the fluid components of the coexistence zone include hydrates, free gas, and water. The total pore volume of these three parts is v, and the pore volume of hydrates is v. h , the free gas pore volume is v g 、The water pore volume is φ w , hydrate saturation is S h =v h / v, free gas saturation is S g =φ g / φ, water saturation is S w =φ w / φ.

[0018] Preferably, in step S3, density, neutron, acoustic wave, resistivity, and nuclear magnetic total porosity logging curves are selected, the following comprehensive logging response equations and constraints are listed, and the objective function for solving the equations is set:

[0019] The comprehensive logging response equations are as follows:

[0020]

[0021] Among them, in the above formula, ρ b , Δt, R t are the response values ​​of nuclear magnetic resonance, density, neutron, acoustic wave and resistivity logging curves at this depth; HI g and HI w are the hydrogen index of natural gas and formation water, P g is the polarizability of hydrogen atoms in natural gas; ρ ma , sh , h , g , w They are the densities of rock skeleton minerals, mud, hydrates, natural gas, and formation water respectively; are the neutron values ​​of rock skeleton minerals, mud, hydrate, natural gas, and formation water respectively; Δt ma , Δt sh , Δt h , Δt g , Δtw are the longitudinal wave time differences of rock skeleton minerals, mud, hydrate, natural gas, and formation water; V ma 、V sh is the volume fraction of rock skeleton and mud; the rock electrical experimental parameters a, m, n are determined by the rock electrical experiments of regional in-situ cores, the mudstone resistivity Rsh is determined by the resistivity curve corresponding to the mudstone section, and the formation water resistivity Rw is calculated from the formation water mineralization determined by the regional water analysis data.

[0022] Preferably, the constraints are:

[0023]

[0024] Preferably, the objective function is:

[0025]

[0026] In the above formula, r is the number of logging curves; u is the number of logging curve data points; v is the number of logging curve depth points; W i,k is the kth logging response value of the i-th fluid component; R i,j is the observed logging response; V k,j is the volume content of each component.

[0027] Preferably, in step S3, the parameters of the model are continuously adjusted so that the theoretical calculated values ​​of acoustic time difference, neutron, density and resistivity are close to the logging response values. ρ b , Δt, R t , and the NMR total porosity continuous measurement curve is consistent with the actual NMR point-measured total porosity of the formation, and the hydrate volume φ is obtained h 、Free gas volume φ g 、Formation water volume φ w , according to the hydrate volume φ h 、Free gas volume φ g 、Formation water volume φ w , and the hydrate saturation S h , free gas saturation S g and formation water saturation S w .

[0028] Preferably, in step S1, a cutoff value method or a two-dimensional data analysis method is used to calculate the volume of water and the volume of free gas at all points.

[0029] Another aspect of the present invention provides a computer device, comprising a storage device and a processor, wherein the storage device stores a computer program, and the processor implements the steps of the above method when executing the computer program.

[0030] Compared with the prior art, the beneficial effects of the present invention are as follows: the present invention combines the multi-dimensional information of conventional logging curves and nuclear magnetic resonance logging curves to establish a rock physical volume model, avoiding the defect that single logging curves such as density, neutron, resistivity, and nuclear magnetic resonance are affected by fluid properties and cannot reflect multiphase fluid information, and solves the problem of low calculation accuracy of gas saturation and hydrate saturation of reservoirs in the hydrate-shallow gas coexistence zone. There are fewer unknowns involved, the method has accurate calculation results, and has a wide range of applications. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] Figure 1 It is a flow chart of the method for calculating the saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone of the present invention;

[0032] Figure 2 To obtain the transverse relaxation time-diffusion coefficient distribution spectrum based on MRF inversion of two-dimensional NMR point measurement mode;

[0033] Figure 3 It is a transverse relaxation time-diffusion coefficient fluid identification chart based on the two-dimensional point measurement mode data of nuclear magnetic resonance logging;

[0034] Figure 4 The cut-off value method is used to quantitatively analyze the water and gas signals and the hydrocarbon correction results map of the transverse relaxation time-diffusion coefficient distribution spectrum;

[0035] Figure 5 This is a schematic diagram of the rock physics volume model of the hydrate-free gas coexistence zone;

[0036] Figure 6 The relationship curve between formation factors and porosity under formation conditions

[0037] Figure 7 It is the relationship curve between resistivity index and water saturation under formation conditions;

[0038] Figure 8 This is a result diagram of evaluating the saturation of the hydrate-free gas coexistence zone based on optimized well logging. DETAILED DESCRIPTION

[0039] The technical solution of the present invention is further described in detail below through specific embodiments and in conjunction with the accompanying drawings:

[0040] Example 1

[0041] like Figure 1 As shown, a method for calculating the saturation of an ultra-shallow natural gas hydrate-free gas coexistence zone comprises the following steps:

[0042] S1. Obtain one-dimensional continuous measurement T2 spectrum data and two-dimensional point measurement mode data of nuclear magnetic resonance logging, and invert the two-dimensional point measurement mode data to obtain the transverse relaxation time-diffusion coefficient distribution spectrum, and identify water and gas signals according to the transverse relaxation time-diffusion coefficient distribution spectrum, such as Figure 3 As shown, the water volume and the free gas volume are calculated according to the identification signal, and the water saturation and the free gas saturation are calculated according to the water volume and the free gas volume respectively;

[0043] S2. Based on the calculated water saturation and free gas saturation, the nuclear magnetic point-measured porosity is corrected for hydrocarbons to obtain the true nuclear magnetic point-measured total porosity of the formation that is not affected by gas content;

[0044] S3. Obtain conventional logging curve data, establish a rock physical volume model of the hydrate-free gas coexistence zone, establish a comprehensive logging response equation group, use the real nuclear magnetic point measurement total porosity of the formation as the calibration data for optimizing the solution of the comprehensive logging response equation group, and use the optimal inversion method to solve the rock skeleton mineral composition and pore fluid composition to obtain the hydrate saturation, free gas saturation and formation water saturation of the coexistence zone.

[0045] It should be noted that in the CMR measurement phase, continuous T2 spectrum data is first acquired, and then different waiting times WT and echo intervals T E , collect multiple sets of echo train two-dimensional point measurement mode (MRF) data, and invert the point measurement mode data to obtain the transverse relaxation time-diffusion coefficient (T2-D) distribution spectrum, such as Figure 2 shown.

[0046] In step S1, multiple CPMG sequences are measured in a two-dimensional point measurement mode, using different waiting times WT and echo intervals T E , collect multiple sets of echo train data, perform two-dimensional inversion on the echo train data to obtain transverse relaxation time-diffusion coefficient spectrum;

[0047]

[0048] In the formula, b(t,T E ) is the echo amplitude, f(T2,D) is the two-dimensional distribution function about the two parameters T2 and D; γ is the gyromagnetic ratio; G is the fixed magnetic field gradient; D is the diffusion coefficient of the fluid; T E is the echo interval; ε is the noise. It should be noted that the CPMG sequence is specifically the Carr-Purcell-Meiboom-Gill sequence, which is a commonly used magnetic resonance imaging technology, mainly used to measure and analyze the spin-spin interaction and dynamic characteristics of the sample.

[0049] In addition, in step S2, the formula for performing hydrocarbon correction on the nuclear magnetic point porosity is as follows:

[0050]

[0051] In the formula, φ cor is the corrected total porosity measured by nuclear magnetic field, i.e. the actual total porosity measured by nuclear magnetic field; φ MRF HI is the total porosity measured by NMR before correction; g HI is the hydrogen index of natural gas; w is the hydrogen content index of water; S w ' is water saturation; S gxo ' is the free gas saturation.

[0052] Among them, in step S3, if Figure 5 As shown in Figure 2, the rock physics volume model for the hydrate-free gas coexistence zone includes:

[0053] For the rock skeleton and clay parts, the mineral types were determined by the quantitative analysis of the whole-rock X-ray diffraction of the core. The volumes of the skeleton and clay parts are V and V respectively. ma 、V sh ;

[0054] Regarding the pore fluid components, the fluid components of the coexistence zone include hydrates, free gas, and water. The total pore volume of these three parts is φ, and the pore volume of hydrates is φ h , the free gas pore volume is φ g 、The water pore volume is φ w , hydrate saturation is S h =φ h / φ, free gas saturation is S g =φ g / φ, water saturation is S w =φ w / φ;

[0055] Since NMR logging detects the relaxation time of hydrogen atoms in pore fluids, and hydrates as solids have no NMR response, the total NMR porosity measures the pore volume occupied by formation water and free gas. In addition, the NMR porosity is significantly smaller than the actual porosity of the reservoir due to the influence of free gas.

[0056] In step S1, the volume of water and the volume of free gas at all points are calculated using the cutoff value method or the two-dimensional data analysis method, such as Figure 4 shown.

[0057] Example 2

[0058] Example 2 is similar to Example 1, except that, in step S3, density, neutron, acoustic wave, resistivity, and nuclear magnetic total porosity logging curves are selected, the following comprehensive logging response equations and constraints are listed, and the objective function for solving the equations is set:

[0059] The comprehensive logging response equations are as follows:

[0060]

[0061] Among them, in the above formula, ρ b , Δt, R t are the response values ​​of nuclear magnetic resonance, density, neutron, acoustic wave and resistivity logging curves at this depth; HI g and HI w are the hydrogen index of natural gas and formation water, P g is the polarizability of hydrogen atoms in natural gas; ρ ma , sh , h , g , w They are the densities of rock skeleton minerals, mud, hydrates, natural gas, and formation water respectively; are the neutron values ​​of rock skeleton minerals, mud, hydrate, natural gas, and formation water respectively; Δt ma , Δt sh , Δt h , Δt g , Δt w are the longitudinal wave time differences of rock skeleton minerals, mud, hydrate, natural gas, and formation water; V ma 、V sh is the volume fraction of rock skeleton and mud; the rock electrical experimental parameters a, m, n are determined by the rock electrical experiments of regional in-situ cores, the mudstone resistivity Rsh is determined by the resistivity curve corresponding to the mudstone section, and the formation water resistivity Rw is calculated from the formation water mineralization determined by the regional water analysis data.

[0062] In this embodiment, the rock electrical parameters are given by Figure 6 , Figure 7 It was determined that: a=1, m=1.64, n=1.84.

[0063] The constraints are:

[0064]

[0065] In addition, the objective function is:

[0066]

[0067] In the above formula, r is the number of logging curves; u is the number of logging curve data points; v is the number of logging curve depth points; W i,k is the kth logging response value of the i-th fluid component; R i,j is the observed logging response; V k,j is the volume content of each component.

[0068] In step S3, the parameters of the model are continuously adjusted so that the theoretical calculation values ​​of acoustic time difference, neutron, density and resistivity are close to the logging response values. ρ b , Δt, R t , and the NMR total porosity continuous measurement curve is consistent with the actual NMR point-measured total porosity of the formation, and the hydrate volume φ is obtained h 、Free gas volume φ g 、Formation water volume φ w , according to the hydrate volume φ h 、Free gas volume φ g 、Formation water volume φ w , and the hydrate saturation S h , free gas saturation S g and formation water saturation S w .

[0069] Example 3

[0070] Take a well drilled in the Qiongdongnan Basin in the South China Sea in 2023 as an example. Figure 8 To explain the results of the treatment using the methods in Example 1 and Implementation 2. Figure 8 The first track is the gamma and wellbore curve, the second track is the depth track, the third track is the induction resistivity curve, the fourth track is the neutron, density and acoustic wave curves, the fifth and sixth tracks are the pressure sampling conclusions, the seventh track is the nuclear magnetic resonance T2 spectrum, the eighth track is the nuclear magnetic resonance point porosity and the continuous measurement nuclear magnetic resonance porosity before hydrocarbon correction, and the two are basically consistent before correction; the ninth track is the skeleton, clay and fluid component profile obtained by this method, and the tenth track is the point measurement porosity and the continuous measurement porosity before and after hydrocarbon correction. It can be seen that the nuclear magnetic resonance porosity calculated by this method is The magnetic porosity (green curve) is consistent with the point-measured nuclear magnetic porosity (red points) after hydrocarbon correction, and there is a difference with the conventional porosity (black), indicating the presence of hydrates in the reservoir. Track 10 is the calculated hydrate saturation (blue curve) and free gas saturation (red curve), indicating that the upper part of the reservoir is mainly hydrates and the lower part is mainly free gas. This understanding is confirmed by the sampling results (the 1779m sample in Track 6 is mainly gas, containing some water decomposed by hydrates; the sample at 1785.7m is pure gas, and the hydrates are not decomposed).

[0071] Example 4

[0072] This embodiment provides a computer device, including a storage device and a processor. The storage device stores a computer program, and the processor implements the steps of the above-mentioned embodiments 1 and 2 when executing the computer program.

[0073] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, and are not intended to limit the embodiments of the present invention. For those skilled in the art, other different forms of changes or modifications can be made based on the above description. It is not necessary and impossible to list all the embodiments here. Any modifications, equivalent substitutions and improvements made within the spirit and principles of the present invention should be included in the protection scope of the claims of the present invention.

Claims

1. A method for calculating the saturation of an ultra-shallow natural gas hydrate-free gas coexistence zone, characterized in that: The following steps are involved: S1, obtaining one-dimensional continuous measurement T2 spectrum data and two-dimensional point measurement mode data of nuclear magnetic resonance logging, and inverting the two-dimensional point measurement mode data to obtain a transverse relaxation time-diffusion coefficient distribution spectrum, identifying water and gas signals according to the transverse relaxation time-diffusion coefficient distribution spectrum, calculating the water volume and free gas volume according to the identification signals, and respectively calculating the water saturation and the free gas saturation according to the water volume and the free gas volume; S2. Based on the calculated water saturation and free gas saturation, the nuclear magnetic point-measured porosity is corrected for hydrocarbons to obtain the true nuclear magnetic point-measured total porosity of the formation that is not affected by gas content; S3. Acquire conventional logging curve data, establish a rock physical volume model of the hydrate-free gas coexistence zone, establish a comprehensive logging response equation group, use the real nuclear magnetic point measured total porosity of the formation as the calibration data for optimizing the solution of the comprehensive logging response equation group, and use the optimal inversion method to solve the rock skeleton mineral composition and pore fluid composition to obtain the hydrate saturation, free gas saturation and formation water saturation of the coexistence zone.

2. The method for calculating saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone according to claim 1, characterized in that: In step S1, in a two-dimensional point measurement mode, multiple CPMG sequences are measured using different waiting times WT and echo intervals T E , collect multiple sets of echo train data, perform two-dimensional inversion on the echo train data to obtain transverse relaxation time-diffusion coefficient spectrum; In the formula, b(t,T E ) is the echo amplitude, f(T2,D) is the two-dimensional distribution function about the two parameters T2 and D; γ is the gyromagnetic ratio; G is the fixed magnetic field gradient; D is the diffusion coefficient of the fluid; T E is the echo interval; ε is the noise.

3. The method for calculating saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone according to claim 1, characterized in that: In step S2, the formula for performing hydrocarbon correction on the nuclear magnetic point porosity is as follows: In the formula, φ cor is the corrected total porosity of nuclear magnetic field point measurement, i.e. the actual total porosity of nuclear magnetic field point measurement of the formation; φ MRF HI is the total porosity measured by NMR before correction; g HI is the hydrogen index of natural gas; w is the hydrogen content index of water; S w ' is water saturation; S gxo ' is the free gas saturation.

4. The method for calculating saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone according to claim 1, characterized in that: In step S3, establishing a rock physical volume model of the hydrate-free gas coexistence zone includes: For the rock skeleton and clay parts, the mineral types were determined by the quantitative analysis of the whole-rock X-ray diffraction of the core. The volumes of the skeleton and clay parts are V and V respectively. ma 、V sh ; Regarding the pore fluid components, the fluid components of the coexistence zone include hydrates, free gas, and water. The total pore volume of these three parts is φ, and the pore volume of hydrates is φ h , the free gas pore volume is φ g 、The water pore volume is φ w , hydrate saturation is S h =φ h / φ, free gas saturation is S g =φ g / v, water saturation is S w =v w / v.

5. The method for calculating the saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone according to claim 4, characterized in that: In step S3, density, neutron, acoustic wave, resistivity, and nuclear magnetic total porosity logging curves are selected, the following comprehensive logging response equations and constraints are listed, and the objective function for solving the equations is set: The comprehensive logging response equations are as follows: Among them, in the above formula, ρ b , Δt, R t are the response values ​​of nuclear magnetic resonance, density, neutron, acoustic wave and resistivity logging curves at this depth; HI g and HI w are the hydrogen index of natural gas and formation water, P g is the polarizability of hydrogen atoms in natural gas; ρ ma , sh , h , g , w They are the densities of rock skeleton minerals, mud, hydrates, natural gas, and formation water respectively; are the neutron values ​​of rock skeleton minerals, mud, hydrate, natural gas, and formation water respectively; Δt ma , Δt sh , Δt h , Δt g , Δt w V are the longitudinal wave time differences of rock skeleton minerals, mud, hydrate, natural gas and formation water respectively; ma 、V sh is the volume fraction of rock skeleton and mud; the rock electrical experimental parameters a, m, n are determined by the rock electrical experiments of regional in-situ cores, the mudstone resistivity Rsh is determined by the resistivity curve corresponding to the mudstone section, and the formation water resistivity Rw is calculated from the formation water mineralization determined by the regional water analysis data.

6. The method for calculating the saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone according to claim 5, characterized in that: The constraints are:

7. The method for calculating the saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone according to claim 6, characterized in that: The objective function is: In the above formula, r is the number of logging curves; u is the number of logging curve data points; v is the number of logging curve depth points; W i,k is the kth logging response value of the i-th fluid component; R i,j is the observed logging response; V k,j is the volume content of each component.

8. The method for calculating saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone according to claim 7, characterized in that: In step S3, the parameters of the model are continuously adjusted so that the theoretical calculated values ​​of acoustic time difference, neutron, density and resistivity are close to the logging response values. ρ b , Δt, R t , and the NMR total porosity continuous measurement curve is consistent with the actual NMR point-measured total porosity of the formation, and the hydrate volume φ is obtained h 、Free gas volume φ g 、Formation water volume φ w , according to the hydrate volume φ h 、Free gas volume φ g 、Formation water volume φ w , and the hydrate saturation S h , free gas saturation S g and formation water saturation S w .

9. The method for calculating saturation of the ultra-shallow natural gas hydrate-free gas coexistence zone according to claim 1, characterized in that: In step S1, the volume of water and the volume of free gas at all points are calculated using a cutoff value method or a two-dimensional data analysis method.

10. A computer device comprising a memory and a processor, wherein the memory stores a computer program, wherein: When the processor executes the computer program, the method according to any one of claims 1 to 9 is implemented.

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