Natural gas hydrate and associated gas co-storage layer saturation determination method and related equipment

Abstract

The invention discloses a natural gas hydrate and associated gas co-storage layer saturation determination method and related equipment. The method comprises the following steps: acquiring acquisition parameters of a target stratum; based on the density data, a density logging response equation is used for processing to obtain the density porosity, and the density porosity and the neutron porosity are combined for conversion to obtain the real formation porosity; based on the porosity and resistivity of the real stratum, water saturation is obtained through processing according to a preset formula; on the basis of the density data, the real formation porosity and the water saturation, the hydrate saturation is obtained through back-stepping according to the gas-bearing correction principle; based on the water saturation and the hydrate saturation, the gas saturation of the target stratum is obtained through back-stepping. Derivation and inversion are carried out based on a physical logging response equation and a classical theoretical formula, linear regression dependence on core analysis data in a specific area is abandoned, the theoretical basis of the method is firmer, and the method can be widely applied to the technical field of stratum determination.

Description

Technical Field

[0001] This invention relates to the field of formation determination technology, and in particular to a method and related equipment for determining the saturation of natural gas hydrate and associated gas co-storage layers. Background Technology

[0002] During hydrate drilling, the coexistence of natural gas hydrates and associated gas has been commonly found in hydrate deposit systems. Calculating the hydrate saturation and gas saturation of the coexisting natural gas hydrate and associated gas reservoirs has always been a technical challenge for geologists and geophysicists.

[0003] The existing methods for calculating the saturation of natural gas hydrate and associated gas co-reservoir using well logging data have the following drawbacks: (1) Natural gas hydrate and associated gas co-storage layers are often deep-sea shallow loose formations. In addition, the formation contains natural gas, sonic velocity logging instruments receive formation sonic signals that are significantly weakened, making it impossible to extract accurate sonic velocity, thus reducing the accuracy of saturation calculation using sonic velocity.

[0004] (2) Nuclear magnetic resonance logging is a special and expensive logging method. Not every hydrate exploration well will be logged with nuclear magnetic resonance, which restricts the use of density and nuclear magnetic resonance logging to calculate saturation.

[0005] (3) The linear regression formula based on the dual parameters of core analysis saturation and density and neutron porosity has regional limitations and poor adaptability to areas where hydrate drilling and core analysis have not been carried out. Summary of the Invention

[0006] The main objective of this invention is to provide a method, system, electronic device, storage medium, and program product for determining the saturation of a natural gas hydrate and associated gas co-storage layer, aiming to solve at least one problem in the prior art.

[0007] To achieve the above objectives, one aspect of this invention provides a method for determining the saturation of a natural gas hydrate and associated gas co-storage layer, the method comprising: Acquire the target formation's parameters, including density data, neutron porosity, and resistivity; Density porosity is obtained by processing density data using density logging response equations, and then the actual formation porosity is obtained by combining density porosity and neutron porosity. Based on the actual formation porosity and resistivity, the water saturation is obtained by processing with a preset formula. Based on density data, actual formation porosity, and water saturation, the hydrate saturation is inferred by using the gas correction principle. The gas saturation of the target formation is obtained based on the water saturation and the hydrate saturation.

[0008] In some embodiments, the density data comprises a density logging value, a matrix density and a formation water density, the density porosity is obtained based on the density data using a density logging response equation, comprising the following steps: The density porosity is obtained according to a ratio of a difference between the density logging value and the matrix density and a difference between the formation water density and the matrix density; The expression of the density porosity is: ; In the formula, denotes the density porosity; denotes the density logging value; denotes the matrix density; denotes the formation water density.

[0009] In some embodiments, the real formation porosity is obtained by converting the density porosity and the neutron porosity, comprising the following steps: The square root of the mean of the square of the density porosity and the square of the neutron porosity is obtained to obtain the real formation porosity; The expression of the real formation porosity is: ; In the formula, denotes the real formation porosity; denotes the density porosity; denotes the neutron porosity.

[0010] In some embodiments, the resistivity comprises a formation water resistivity and a formation resistivity, the preset formula comprises an Archie formula, the water saturation is obtained based on the real formation porosity and the resistivity using the preset formula, comprising the following steps: The product of the formation water resistivity and a preset lithology coefficient is taken as a first value; The preset porosity index is taken as an index of the real formation porosity to perform an exponent operation, and the product of the result of the exponent operation and the formation resistivity is taken as a second value; The ratio of the first value and the second value is taken as a target value; The preset saturation index is taken as a root index to perform a square root operation on the target value to obtain the water saturation; The expression of the water saturation is: ; In the formula, denotes the water saturation; denotes the saturation index; and represents a lithology factor; represents a formation water resistivity; represents a true formation porosity; represents a pore index; represents a formation resistivity.

[0011] In some embodiments, the resistivity further comprises a pure rock resistivity of water-saturated rock, and the method further comprises the following steps: obtaining a formation factor according to a ratio of the pure rock resistivity of water-saturated rock to the formation water resistivity; obtaining the pore index according to a relationship between the formation factor and the true formation porosity in a double logarithmic coordinate; wherein the formation factor and the expression of the relationship between the formation factor and the true formation porosity are: ; In the formula, represents the formation factor; represents the pure rock resistivity of water-saturated rock; represents the formation water resistivity.

[0012] In some embodiments, the density data comprises a density logging value, a matrix density, a formation water density, a hydrate density and an associated gas density, and based on the density data, the true formation porosity and the water saturation, a hydrate saturation is obtained by using a gas correction principle, comprising the following steps: obtaining a relationship between the hydrate saturation and the density data, the true formation porosity and the water saturation based on the gas correction principle, and then calculating the hydrate saturation by using the density data, the true formation porosity and the water saturation; wherein the expression of the gas correction principle is: ; the expression of the hydrate saturation is: ; In the formula, , , , and represent the density logging value, the matrix density, the formation water density, the hydrate density and the associated gas density, respectively; represents the true formation porosity; represents the water saturation; represents the hydrate saturation.

[0013] In some embodiments, a gas saturation of a target formation is obtained based on the water saturation and the hydrate saturation, comprising the following steps: The gas saturation of the target formation is obtained by subtracting the water saturation and the hydrate saturation from 1.

[0014] To achieve the above object, another aspect of the embodiment of the present application provides a system for determining the saturation of a natural gas hydrate and associated gas co-storage layer, which comprises: a data acquisition module configured to acquire acquisition parameters of a target formation, the acquisition parameters comprising density data, neutron porosity and resistivity; a first data processing module configured to process the density data by using a density logging response equation to obtain a density porosity, and convert the density porosity and the neutron porosity to obtain a real formation porosity; a second data processing module configured to process the real formation porosity and the resistivity by using a preset formula to obtain a water saturation; a third data processing module configured to process the density data, the real formation porosity and the water saturation by using a gas correction principle to obtain a hydrate saturation; a fourth data processing module configured to obtain a gas saturation of the target formation by subtracting the water saturation and the hydrate saturation from 1.

[0015] In some embodiments, the resistivity comprises a formation water resistivity and a pure rock resistivity of saturated water, and the system further comprises a fifth data processing module configured to perform the following operations: obtain a formation factor according to a ratio of the pure rock resistivity of saturated water to the formation water resistivity; convert a pore index according to a relationship between the formation factor and the real formation porosity in a double logarithmic coordinate; wherein the expression of the formation factor and the relationship between the formation factor and the real formation porosity is: ; In the formula, wherein, f represents the formation factor; r represents the pure rock resistivity of saturated water; Rw represents the formation water resistivity.

[0016] To achieve the above object, another aspect of the embodiment of the present application provides an electronic device, which comprises a memory and a processor, the memory stores a computer program, and the processor implements the foregoing method when executing the computer program.

[0017] To achieve the above object, another aspect of the embodiment of the present application provides a computer readable storage medium, which stores a computer program, and the computer program is executed by a processor to implement the foregoing method.

[0018] To achieve the above object, another aspect of the embodiment of the present application provides a computer program product comprising a computer program, which, when executed by a processor, implements the foregoing method The embodiment of the present application at least has the following beneficial effects: the present application provides a natural gas hydrate and associated gas co-storage layer saturation determination method, system, electronic equipment, storage medium and program product, the scheme obtains the acquisition parameters of the target formation, the acquisition parameters include density data, neutron porosity, resistivity; based on the density data, the density porosity is obtained by using the density logging response equation processing, and the real formation porosity is obtained by jointing the density porosity and the neutron porosity; based on the real formation porosity and the resistivity, the water saturation is obtained by using the preset formula processing; based on the density data, the real formation porosity and the water saturation, the hydrate saturation is obtained by using the gas correction principle to deduce; and the gas saturation of the target formation is obtained based on the water saturation and the hydrate saturation. The embodiment of the present application explicitly excludes the dependence on acoustic velocity logging, and the more reliable formation porosity is obtained by the joint use of density and neutron porosity. Secondly, the embodiment of the present application only uses three most conventional and necessary logging data of density, neutron and resistivity, without expensive and not popular nuclear magnetic resonance logging, greatly reducing the application threshold and cost of the method, and having excellent universality. Finally, the technical core of the embodiment of the present application is deduced and inverted based on the physical logging response equation and the classical theoretical formula, and the linear regression dependence on the core analysis data of a specific area is abandoned, so that the theoretical basis of the method is more solid, and the application scope is no longer limited to the cored area, and can be extended to new exploration areas. BRIEF DESCRIPTION OF DRAWINGS

[0019] Figure 1 It is an implementation environment schematic diagram of the natural gas hydrate and associated gas co-storage layer saturation determination method provided by the embodiment of the present application. Figure 2 It is a flow schematic diagram of the natural gas hydrate and associated gas co-storage layer saturation determination method provided by the embodiment of the present application. Figure 3 It is an expansion flow schematic diagram of the density porosity provided by the embodiment of the present application. Figure 4 It is an expansion flow schematic diagram of the real formation porosity provided by the embodiment of the present application. Figure 5 It is an expansion flow schematic diagram of step S300 provided by the embodiment of the present application. Figure 6 It is an expansion flow schematic diagram of the porosity index provided by the embodiment of the present application. Figure 7is a schematic diagram of a data example of a calculation result of a shale silt type natural gas hydrate and associated gas co-storage layer saturation provided by an embodiment of the present application; Figure 8 is a schematic diagram of a data example of a calculation result of a sandy type natural gas hydrate and associated gas co-storage layer saturation provided by an embodiment of the present application; Figure 9 is a schematic diagram of a structure example of a natural gas hydrate and associated gas co-storage layer saturation determination system provided by an embodiment of the present application; Figure 10 is a structural schematic diagram of an electronic device provided by an embodiment of the present application. DETAILED DESCRIPTION

[0020] In order to make the purpose, technical scheme and advantages of the present application clearer and more comprehensible, the present application will be further described in detail below in combination with the drawings and embodiments. It should be understood that the specific embodiments described herein are only used to explain the present application and are not used to limit the present application. When the following description relates to the drawings, the same numbers in different drawings represent the same or similar elements unless otherwise indicated. The implementation described in the following exemplary embodiments does not represent all the implementations consistent with the embodiments of the present application, but is only an example of the system and method consistent with some aspects of the embodiments of the present application as detailed in the appended claims.

[0021] It can be understood that the terms "first", "second", and the like used in the present application can be used herein to describe various concepts, but unless specifically stated, these concepts are not limited by these terms. These terms are only used to distinguish one concept from another. For example, without departing from the scope of the embodiments of the present application, the first information can also be referred to as the second information, and similarly, the second information can also be referred to as the first information. Depending on the context, the word "if" as used herein can be interpreted as "when" or "when" or "in response to determining".

[0022] The terms "at least one", "multiple", "each", "any" and the like used in the present application include one, two or more than two, multiple includes two or more than two, each refers to each of the corresponding multiple, and any refers to any one of the multiple.

[0023] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as understood by those skilled in the art to which the present application belongs. The terms used herein are only for the purpose of describing the embodiments of the present application and are not intended to limit the present application.

[0024] In order to facilitate the understanding of the technical solutions of the present application, first, the professional technical terms possibly involved in the technical solutions of the present application are explained and described: Natural gas hydrate and associated gas coexistence reservoir: a formation filled with liquid water, solid natural gas hydrate and gaseous natural gas in the pore space; Porosity logging: mainly refers to sonic logging, density logging and neutron porosity logging; Porosity: the percentage of the pore volume of the rock to the rock volume; Hydrate saturation: the percentage of the hydrate volume of the rock to the pore volume; Gas saturation: the percentage of the gas volume of the rock to the pore volume.

[0025] In the related art, the natural gas hydrate and associated gas coexistence reservoir often belongs to a deep-sea shallow loose formation, and the sonic logging instrument receives a significantly weakened formation sonic signal due to the influence of the formation containing natural gas, so that an accurate sonic velocity cannot be extracted, thereby reducing the accuracy of calculating the saturation by using the sonic velocity. The nuclear magnetic resonance logging is a special and expensive logging method, and not every hydrate exploration well will carry out the nuclear magnetic resonance logging, so that the use of the density and nuclear magnetic resonance logging to calculate the saturation is restricted. The linear regression formula based on the core analysis saturation and the density and neutron porosity double parameters has regional limitations, and has poor adaptability to the region where the core analysis is not carried out.

[0026] Therefore, the embodiments of the present application provide a natural gas hydrate and associated gas coexistence reservoir saturation determination method and related equipment, which obtains the acquisition parameters of the target formation, the acquisition parameters including density data, neutron porosity and resistivity; the density porosity is obtained by using the density logging response equation based on the density data, and the real formation porosity is obtained by combining the density porosity and the neutron porosity; the water saturation is obtained by using a preset formula based on the real formation porosity and the resistivity; the hydrate saturation is obtained by using the gas correction principle based on the density data, the real formation porosity and the water saturation; and the gas saturation of the target formation is obtained by inversely deducing based on the water saturation and the hydrate saturation. The embodiments of the present application explicitly exclude the dependence on the sonic logging, and the more reliable formation porosity is obtained by the joint use of the density and the neutron porosity. Secondly, the embodiments of the present application only use the three most common and necessary logging data of the density, the neutron and the resistivity, without the expensive and not popular nuclear magnetic resonance logging, so that the application threshold and the cost of the method are greatly reduced, and the method has excellent universality. Finally, the technical kernel of the embodiments of the present application is deduced and inverted based on the physical logging response equation and the classical theoretical formula, and the linear regression dependence on the core analysis data of a specific region is abandoned, so that the theoretical basis of the method is more solid, and the application range is no longer limited to the cored region, and can be extended to new exploration regions.

[0027] It can be understood that the natural gas hydrate and associated gas co-storage layer saturation determination method provided by the present application can be applied to any computer device with data processing and calculation capability, and the computer device can be various terminals or servers. When the computer device in the embodiment is a server, the server is an independent physical server, or a server cluster or distributed system composed of multiple physical servers, or a cloud server providing cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communication, middleware services, domain name services, security services, CDN (Content Delivery Network), and basic cloud computing services such as big data and artificial intelligence platforms. Alternatively, the terminal is a smart phone, a tablet computer, a notebook computer, a desktop computer, and the like, but is not limited thereto.

[0028] As shown in Figure 1 , it is an implementation environment schematic diagram provided by the embodiment of the present application. Referring to Figure 1 , the implementation environment includes at least one terminal 102 and a server 101. The terminal 102 and the server 101 can be connected through wireless or wired network connection to complete data transmission and exchange.

[0029] The server 101 can be an independent physical server, or a server cluster or distributed system composed of multiple physical servers, or a cloud server providing cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communication, middleware services, domain name services, security services, CDN (Content Delivery Network), and basic cloud computing services such as big data and artificial intelligence platforms.

[0030] In addition, the server 101 can also be a node server in a blockchain network. The blockchain is a new application mode of distributed data storage, point-to-point transmission, consensus mechanism, encryption algorithm, and other computer technologies.

[0031] The terminal 102 can be a smart phone, a tablet computer, a notebook computer, a desktop computer, a smart speaker, a smart watch, and the like, but is not limited thereto. The terminal 102 and the server 101 can be directly or indirectly connected through wired or wireless communication, and the present application embodiment does not limit this.

[0032] Exemplarily, based on Figure 1In the illustrated implementation environment, the embodiment of the present application provides a natural gas hydrate and associated gas co-storage layer saturation determination method. The natural gas hydrate and associated gas co-storage layer saturation determination method is taken as an example to be applied to the server 101. It can be understood that the natural gas hydrate and associated gas co-storage layer saturation determination method can also be applied to the terminal 102.

[0033] Referring to Figure 2 , Figure 2 is an optional flowchart of the natural gas hydrate and associated gas co-storage layer saturation determination method provided by the embodiment of the present application. The execution subject of the natural gas hydrate and associated gas co-storage layer saturation determination method can be any one of the foregoing computer devices (including a server or a terminal). Figure 2 The method in the embodiment can include but is not limited to steps S100 to S500.

[0034] In step S100, the acquisition parameters of the target formation are obtained. The acquisition parameters include density data, neutron porosity, and resistivity. For example, the density data includes density logging values, skeleton density, formation water density, hydrate density, and associated gas density. The resistivity includes formation water resistivity, formation resistivity, and pure rock resistivity of saturated water. Specifically, the acquisition parameters of the target formation region can be acquired by related logging equipment to provide a data processing basis for subsequent processing steps.

[0035] In step S200, the density porosity is obtained by processing the density data based on a density logging response equation. The real formation porosity is obtained by converting the density porosity and the neutron porosity. It should be noted that the density data includes the density logging values, the skeleton density, and the formation water density. In some embodiments, as shown in Figure 3 The density porosity is obtained by processing the density data based on the density logging response equation, which can include the following steps: S210, obtaining the density porosity according to the ratio of the difference between the density logging values and the skeleton density to the difference between the formation water density and the skeleton density.

[0036] For example, in some specific embodiments, since the density value (0.92 g / cm 3 ) of the hydrate in the formation pore space is close to the density (1 g / cm 3 ) of water, the density porosity of the formation is calculated by using a simple density logging response equation , as shown in formula (1). Here, the density logging is not corrected for gas.

[0037] (1) Specifically, the embodiment of the present application directly calculates the density porosity by using the physical principle of the density logging response equation, ensures the scientificity and reliability of the calculation of the basic parameter, provides accurate data input for the subsequent steps, and avoids the error accumulation caused by inaccurate parameter calculation.

[0038] It should be noted that, as shown in Figure 4 , the true formation porosity obtained by combining the density porosity and the neutron porosity can include the following steps: S220, square root of the mean value of the square value of the density porosity and the square value of the neutron porosity to obtain the true formation porosity.

[0039] Exemplarily, in some specific embodiments, because the reservoir contains gas, the density porosity increases and the neutron porosity decreases, so the true formation porosity of the reservoir coexisting with natural gas hydrate and associated gas is calculated by combining the density porosity and the compensated neutron porosity , as shown in formula (2): (2) Specifically, the embodiment of the present application provides a porosity calculation method capable of effectively suppressing the influence of natural gas (associated gas). Since natural gas can make the density porosity value higher and the neutron porosity value lower, such mathematical combination processing (such as taking the root mean square) can neutralize the influence of gas, so as to obtain a “true” porosity closer to the actual formation condition, and significantly improve the calculation accuracy of the key parameter.

[0040] Specifically, in formula (1) and formula (2): , and are the true formation porosity, the density porosity and the neutron porosity, respectively, with unit of g / cm 3 . , and are the density logging value, the matrix density (the value of sandstone is 2.65, and the actual value of the region needs to be taken due to different lithology in different regions) and the formation water density (the value is usually taken as 1), respectively, with unit of g / cm 3 .

[0041] Step S300, based on the true formation porosity and the resistivity, the water saturation is obtained by using a preset formula; It should be noted that the resistivity includes the formation water resistivity and the formation resistivity, and the preset formula includes the Archie formula, and in some embodiments, as shown in Figure 5As shown, step S300 can include the following steps: S310, taking the product of the formation water resistivity and the preset lithology coefficient as a first value; S320, taking the preset porosity index as an exponent for power operation of the true formation porosity, and taking the product of the power operation result and the formation resistivity as a second value; S330, taking the ratio of the first value and the second value as a target value; and S340, taking the preset saturation index as a root index to perform square root operation on the target value to obtain the water saturation.

[0042] As shown, step S300 can include the following steps: S310, taking the product of the formation water resistivity and the preset lithology coefficient as a first value; S320, taking the preset porosity index as an exponent for power operation of the true formation porosity, and taking the product of the power operation result and the formation resistivity as a second value; S330, taking the ratio of the first value and the second value as a target value; and S340, taking the preset saturation index as a root index to perform square root operation on the target value to obtain the water saturation. As shown, step S300 can include the following steps: S310, taking the product of the formation water resistivity and the preset lithology coefficient as a first value; S320, taking the preset porosity index as an exponent for power operation of the true formation porosity, and taking the product of the power operation result and the formation resistivity as a second value; S330, taking the ratio of the first value and the second value as a target value; and S340, taking the preset saturation index as a root index to perform square root operation on the target value to obtain the water saturation. As shown, step S300 can include the following steps: S310, taking the product of the formation water resistivity and the preset lithology coefficient as a first value; S320, taking the preset porosity index as an exponent for power operation of the true formation porosity, and taking the product of the power operation result and the formation resistivity as a second value; S330, taking the ratio of the first value and the second value as a target value; and S340, taking the preset saturation index as a root index to perform square root operation on the target value to obtain the water saturation. (3) In the formula, the water saturation is %, the lithology coefficient is generally set as 1, the porosity index is %, the saturation index is in the range of 1.715 (unconsolidated formation) to 2.1661 (sandstone), the formation porosity is %, and the formation water resistivity and the formation resistivity are both in units of Ω·m. The saturation index is in the range of 1.715 (unconsolidated formation) to 2.1661 (sandstone).

[0043] Specifically, the embodiment of the present application uses the most mature and reliable electrical logging interpretation theory verified by the global oil and gas industry for a long time. This step does not depend on any regional empirical coefficient, but is based on the physical response (resistivity) of the formation, ensuring the objectivity and theoretical consistency of the water saturation calculation result, and further strengthening the universality and scientificity of the method of the present application.

[0044] In some embodiments, the resistivity also includes the pure rock resistivity of saturated water, as shown in the formula (2). Figure 6 As shown, the method can further include the following steps: T100, obtaining a formation factor according to the ratio of the pure rock resistivity of saturated water and the formation water resistivity; and T200, converting the porosity index according to the relationship between the formation factor and the true formation porosity in the double logarithmic coordinate to obtain the porosity index.

[0045] As shown, in some specific embodiments, the resistivity of the coexisting storage layer of the natural gas hydrate and the associated gas is obtained, and the true formation porosity obtained in the previous step is combined to obtain the formation factor. ​​​​​​​​​​​​The ratio of the value of the slope of the linear relationship between the value of the resistivity and the value of the porosity The relationship in the double logarithmic coordinates gives the pore index The value, see formula (4): (4) Specifically, the embodiment of the present application provides a means for accurately determining key rock-electricity parameters. The value is obtained by the relationship between the formation factor and the porosity , avoiding the error that may be caused by using the empirical value, making the subsequent water saturation calculation based on the Archie formula more accurate, and improving the reliability of the final results of the entire method chain.

[0046] In addition, it should be noted that in some optional embodiments, the preset formula also includes the Indonesia formula and the regional empirical formula; specifically, the water saturation of the natural gas hydrate and associated gas coexisting reservoir is calculated by using the Archie formula, i.e. formula (3), which is a conventional method, in addition, the Indonesia formula and the regional empirical formula can also be used to calculate the water saturation.

[0047] Step S400, based on the density data, the true formation porosity and the water saturation, the hydrate saturation is obtained by using the gas correction principle; It should be noted that the density data includes the density logging value, the skeleton density, the formation water density, the hydrate density and the associated gas density, and in some embodiments, step S400 can include the following steps: based on the relationship between the hydrate saturation obtained by using the gas correction principle and the density data, the true formation porosity and the water saturation, the hydrate saturation is calculated by using the density data, the true formation porosity and the water saturation.

[0048] Exemplarily, in some specific embodiments, the density data of the natural gas hydrate and associated gas coexisting reservoir is obtained, and the true formation porosity and the water saturation obtained by the previous step are obtained. Based on the idea of gas correction of density logging, see formula (5), and then the method for calculating the hydrate saturation of the natural gas hydrate and associated gas coexisting reservoir by using the density logging is obtained, see formula (6).

[0049] (5) (6) In the formula: , , , , ​Density logging value, skeleton density (2.65 for sandstone, actual value in different regions due to different lithology), formation water density (1), hydrate density (0.92 for type I hydrate) and associated gas density, unit g / cm 3 Other parameters are as follows: The associated gas density is the relative density of the associated gas, which can be calculated according to the ratio of the relative molecular mass of the associated gas to the relative molecular mass 28.97 of air, as shown in formula (7). For example, the relative molecular mass of pure methane associated gas is equal to 16, and the relative density is equal to 0.55.

[0050] (7) In the formula, is the relative molecular mass of the associated gas, dimensionless.

[0051] Specifically, the embodiment of the present application creatively solves the core problem of the coexistence of hydrates and associated gas. The density logging value is affected by two opposite factors, hydrates (high density) and gas (low density). This step realizes the effective separation and quantitative calculation of hydrate saturation in the presence of gas through the principle of gas correction, which is the key technical point of the embodiment of the present application to solve the coexistence problem.

[0052] Step S500, based on the water saturation and the hydrate saturation, the gas saturation of the target formation is obtained by reverse calculation; It should be noted that in some embodiments, step S500 can include the following steps: the gas saturation of the target formation is obtained by subtracting the water saturation and the hydrate saturation from 1.

[0053] For example, in some specific embodiments, the water saturation obtained by combining the previous steps and the hydrate saturation , the gas saturation of the natural gas hydrate and associated gas coexisting reservoir can be calculated by .

[0054] Specifically, after obtaining the water saturation and the hydrate saturation of the previous two steps, the gas saturation as the remaining part of the pore space can be reliably obtained by subtraction, without introducing additional complex and uncertain calculation models, ensuring the integrity and rationality of the final result.

[0055] To explain the principle of the technical scheme of the present application, the overall process of the present application will be described in conjunction with some specific embodiments. It should be understood that the following is an explanation of the technical principle of the present application and cannot be regarded as a limitation of the present application.

[0056] First of all, it needs to be pointed out that natural gas hydrate is a kind of high-efficiency clean potential future energy, which is widely distributed in global oceans and land permafrost zones. It is called "the second petroleum resource", and the global resource amount is as high as 2.0 x 1012 tons of oil equivalent, which is equivalent to twice the total amount of global proven traditional fossil fuel carbon. Natural gas hydrate is of great significance to the future energy pattern, energy composition and strategic reserve of the world, so it has attracted many scientists around the world to explore and develop research, and constantly promote the industrialization process. 16 m 3 It is called "the second petroleum resource", and the global resource amount is as high as 2.0 x 1012 tons of oil equivalent, which is equivalent to twice the total amount of global proven traditional fossil fuel carbon. Natural gas hydrate is of great significance to the future energy pattern, energy composition and strategic reserve of the world, so it has attracted many scientists around the world to explore and develop research, and constantly promote the industrialization process.

[0057] Logging is an essential technical means in the process of natural gas hydrate drilling, which can accurately identify hydrate and gas reservoirs, and through logging evaluation, important geological parameters such as porosity, permeability and saturation of the reservoir can be calculated, providing parameter basis for hydrate reserve calculation. The accurate calculation of hydrate saturation and gas saturation in natural gas hydrate and associated gas coexisting reservoirs using logging data is of great significance to the accurate calculation of resource reserves.

[0058] Specifically, the prior art scheme includes: 1) Identification of natural gas hydrate and associated gas coexisting reservoirs: The hydrate reservoir in the sea area is often identified by the increase of the shallow resistivity logging value and the increase of the acoustic velocity logging value. The underlying hydrate reservoir is often associated with natural gas, and the core analysis of hydrate drilling confirms that hydrate still develops in the associated gas reservoir, which is a natural gas hydrate and associated gas coexisting reservoir. Such reservoirs can be comprehensively identified by high resistivity, low density, low neutron porosity, low P-wave velocity, high S-wave velocity and high shear modulus and other logging response characteristics.

[0059] 2) Porosity calculation of natural gas hydrate and associated gas coexisting reservoirs: In the logging evaluation of hydrate reservoirs, density logging is usually used to calculate the porosity of the reservoir. The gas content of natural gas hydrate and associated gas coexisting reservoirs will cause the density and neutron porosity logging values of the formation to decrease, and the formation porosity calculated by density logging will be larger than the true formation porosity. Many studies have proposed to jointly use density porosity and neutron porosity to calculate the true formation porosity, that is, to correct the influence of natural gas on porosity logging. and neutron porosity to calculate the true formation porosity , that is , to correct the influence of natural gas on porosity logging.

[0060] 3) Saturation calculation of natural gas hydrate and associated gas coexisting reservoirs: Core analysis hydrate saturation is obtained by two methods of non-pressure-maintaining core chloride ion desalination and pressure-maintaining core gas release, and is used to calibrate the logging reservoir evaluation results.

[0061] The saturation logging quantitative calculation method of the natural gas hydrate and associated gas co-stored layer mainly includes three kinds: 1. The elastic velocity simulation method based on the rock physical model of the longitudinal wave and the transverse wave velocity is used to calculate the hydrate saturation and the gas saturation; 2. The density and the nuclear magnetic resonance logging joint method is used to calculate the hydrate saturation and the gas saturation; 3. The linear regression formula of the core analysis gas saturation and the density and the neutron porosity double parameters is established, and then the hydrate saturation is determined in combination with the formation water saturation.

[0062] However, the prior art scheme has many defects (for specific reference, see the background art description, which is not repeated here).

[0063] In view of this, the present application aims to conveniently and accurately realize the calculation of the two saturations by using the porosity logging data. Specifically, the embodiments of the present application can realize the following process: (1) Step one, calculating the real formation porosity of the natural gas hydrate and associated gas co-stored layer: The density logging value of the natural gas hydrate and associated gas co-stored layer is obtained and the neutron porosity logging value . Since the density value (0.92 g / cm 3 ) of the hydrate in the formation pore space is close to the density (1 g / cm 3 ) of water, the density porosity of the formation is calculated by using a simple density logging response equation, as shown in formula (1), and the density logging is not corrected for gas here. Because the reservoir gas causes the density porosity to increase and the neutron porosity to decrease, the real formation porosity of the natural gas hydrate and associated gas co-stored layer is calculated in combination with the density porosity and the compensated neutron porosity, as shown in formula (2): (1) (2) In the formula, , and are the real formation porosity, the density porosity and the neutron porosity, respectively, and the unit is %; , and are the density logging value, the skeleton density (the value of sandstone is 2.65, and the actual value of the region needs to be taken due to different lithology in different regions) and the formation water density (the value is usually taken as 1), and the unit is g / cm 3 .

[0064] (2) Step two, calculating the water saturation of the natural gas hydrate and associated gas co-stored layer: Obtain the resistivity logging values ​​of the natural gas hydrate and associated gas co-storage layer, and combine them with the actual formation porosity obtained in step one. The Archie formula was used to calculate the water saturation of the formation. See formula (3) for details: (3) In the formula: Water saturation, in % %. , Lithology coefficient; Porosity index; The saturation index; Formation porosity, in % %. , These are the formation water resistivity and formation resistivity, respectively, in Ω·m. Other parameter values ​​are as follows: Generally, let the lithology coefficient be... , All equal to 1, through the stratigraphic factor (Resistivity of water-saturated pure rock) With formation water resistivity The ratio of porosity to porosity The porosity index is obtained from the relationship in a log-log coordinate system. Values, see formula (4); saturation index The value ranges from 1.715 (unconsolidated strata) to 2.1661 (sandstone).

[0065] (4) By obtaining the geothermal gradient and formation water salinity of the study area, and using Schlumberger's NaCl solution resistivity chart, the formation water resistivity can be obtained. .

[0066] (3) Step 3: Calculate the hydrate saturation of the natural gas hydrate and associated gas co-storage layer: Obtain density logging values ​​of natural gas hydrate and associated gas co-reservoir layers. And to obtain the true formation porosity obtained from step one. and the water saturation obtained in step two Based on the idea of ​​correcting for gas content using density logging, see formula (5) for details, and then obtain the hydrate saturation of the co-storage layer of natural gas hydrate and associated gas using density logging. For details on the method, please refer to formula (6).

[0067] (5) (6) In the formula: , , , , Density logging value, matrix density (2.65 for sandstone, actual value in different regions due to different lithology), formation water density (1 is usually taken), hydrate density (0.92 for type I hydrate) and associated gas density, unit g / cm 3 Other parameter values are as follows: The associated gas density is the relative density of associated gas, which can be calculated according to the ratio of the relative molecular mass of associated gas to the relative molecular mass 28.97 of air, as shown in formula (7). For example, the relative molecular mass of pure methane associated gas is equal to 16, and the relative density is equal to 0.55.

[0068] (7) In the formula, is the relative molecular mass of associated gas, dimensionless.

[0069] (4) Step four, calculating the gas saturation of the coexisting storage layer of natural gas hydrate and associated gas: The water saturation obtained in step two and the hydrate saturation obtained in step three are combined to calculate the gas saturation of the coexisting storage layer of natural gas hydrate and associated gas.

[0070] (5) Application effect analysis of the method: Figure 7 and Figure 8 respectively show the saturation calculation results of the coexisting storage layer of natural gas hydrate and associated gas of the argillaceous silt type and the sandy type, Figure 7 is a data example of the saturation calculation results of the coexisting storage layer of natural gas hydrate and associated gas of the argillaceous silt type, Figure 8 is a data example of the saturation calculation results of the coexisting storage layer of natural gas hydrate and associated gas of the sandy type. From Figure 7 it can be seen that in the coexisting storage layer of natural gas hydrate and associated gas, the hydrate saturation calculated according to the method has good consistency with the core analysis hydrate saturation (chloride-diluted hydrate saturation and pressure-maintained core gas release hydrate saturation), proving that the method of the embodiment of the present application is feasible and reliable.

[0071] ​In summary, the embodiment of the present application obtains the hydrate saturation calculation method of the natural gas hydrate and associated gas coexisting reservoir based on the gas correction idea of the density logging, that is, formulas (5) and (6), and the associated gas density value in the formula is the relative density of the associated gas. Specifically, the present application overcomes the shortcomings of the prior art, selects the density and neutron porosity, two conventional logging methods that will be definitely carried out in the natural gas hydrate drilling process, avoids the potential influence of the stratum loosening and gas on the logging data distortion, is not constrained by whether the regional hydrate saturation core analysis is carried out, and is suitable for the saturation calculation of the natural gas hydrate and associated gas coexisting reservoir in different regions, different lithology and different natural gas component types.

[0072] As shown in Figure 9 The embodiment of the present application also provides a natural gas hydrate and associated gas coexisting reservoir saturation determination system 900, which can implement the above method, and the system comprises: A data acquisition module 910 is configured to acquire acquisition parameters of a target stratum, and the acquisition parameters comprise density data, neutron porosity and resistivity. A first data processing module 920 is configured to obtain density porosity by processing the density data based on a density logging response equation, and to obtain real stratum porosity by converting the density porosity and the neutron porosity. A second data processing module 930 is configured to obtain water saturation by processing the real stratum porosity and the resistivity based on a preset formula. A third data processing module 940 is configured to obtain hydrate saturation by inversely deducing based on the density data, the real stratum porosity and the water saturation by using a gas correction principle. A fourth data processing module 950 is configured to obtain gas saturation of the target stratum by inversely deducing based on the water saturation and the hydrate saturation.

[0073] In some embodiments, the resistivity comprises formation water resistivity and pure rock resistivity of saturated water, and the system can further comprise a fifth data processing module configured to perform the following operations: Obtaining a formation factor according to the ratio of the pure rock resistivity of saturated water to the formation water resistivity; Obtaining a pore index according to the relationship between the formation factor and the real stratum porosity in a double logarithmic coordinate; Wherein, the expression of the formation factor and the relationship between the formation factor and the real stratum porosity is: ; In the formula, denotes the formation factor; denotes the pure rock resistivity of saturated water; denotes the formation water resistivity.

[0074] It can be understood that the contents in the above method embodiments are all applicable to the present system embodiments, the present system embodiments specifically implement the functions same as the above method embodiments, and achieve the same beneficial effects as the above method embodiments.

[0075] The present application also provides an electronic device, which comprises a memory and a processor. The memory stores a computer program, and the processor implements the above method when executing the computer program. The electronic device can be any smart terminal, such as a tablet computer or a vehicle-mounted computer.

[0076] It can be understood that the contents in the above method embodiments are all applicable to the present device embodiments, the present device embodiments specifically implement the functions same as the above method embodiments, and achieve the same beneficial effects as the above method embodiments.

[0077] As shown in Figure 10 , Figure 10 a hardware structure of an electronic device 1000 of another embodiment is illustrated, which comprises: The processor 1001 can be implemented in a general-purpose CPU (Central Processing Unit), a microprocessor, an application specific integrated circuit (aSIC), or one or more integrated circuits, etc., and is used to execute related programs to implement the technical solutions provided by the present application; The memory 1002 can be implemented in a read-only memory (ROM), a static storage device, a dynamic storage device, or a random access memory (RaM), etc. The memory 1002 can store an operating system and other application programs. When the technical solutions provided by the present application are implemented by software or firmware, the related program codes are stored in the memory 1002 and are called and executed by the processor 1001 to implement the method of the present application; The input / output interface 1003 is used to realize information input and output; The communication interface 1004 is used to realize the communication interaction between the present device and other devices, which can realize communication through a wired manner (such as USB, network cable, etc.) or a wireless manner (such as mobile network, WIFI, Bluetooth, etc.); The bus 1005 transmits information between various components (such as the processor 1001, the memory 1002, the input / output interface 1003, and the communication interface 1004) of the device; The processor 1001, the memory 1002, the input / output interface 1003 and the communication interface 1004 are communicatively connected with each other through the bus 1005.

[0078] The electronic device embodiments described above are merely illustrative, wherein the units described as separate components can or can not be physically separated, i.e., can be located in one place or can be distributed on multiple network units. Part or all of the modules can be selected according to actual needs to achieve the purpose of the embodiment scheme.

[0079] The embodiment of the application further provides a computer readable storage medium, which stores a computer program, and the computer program is executed by a processor to realize the method.

[0080] It can be understood that the content in the above method embodiments is applicable to the present storage medium embodiment, the function realized by the present storage medium embodiment is the same as that of the above method embodiments, and the beneficial effects achieved by the present storage medium embodiment are also the same as those achieved by the above method embodiments.

[0081] The embodiment of the application further provides a computer program product, which comprises a computer program, and the computer program is executed by a processor to realize the method.

[0082] It can be understood that the content in the above method embodiments is applicable to the present program product embodiment, the function realized by the present program product embodiment is the same as that of the above method embodiments, and the beneficial effects achieved by the present program product embodiment are also the same as those achieved by the above method embodiments.

[0083] The memory is a non-transitory computer readable storage medium, which can be used to store non-transitory software programs and non-transitory computer executable programs. In addition, the memory can include a high-speed random access memory, and can also include a non-transitory memory, such as at least one magnetic disk storage device, a flash memory device, or other non-transitory solid-state memory device. In some embodiments, the memory can optionally include a memory remotely arranged relative to the processor, and these remote memories can be connected to the processor through a network. Examples of the above network include but are not limited to the Internet, an intranet, a local area network, a mobile communication network, and a combination thereof.

[0084] The natural gas hydrate and associated gas co-storage layer saturation determination method, system, electronic device, storage medium and program product provided by the embodiment of the present application obtain the collection parameters of the target formation, the collection parameters including density data, neutron porosity and resistivity; the density porosity is obtained by processing the density logging response equation based on the density data, and the real formation porosity is obtained by conversion in combination with the density porosity and the neutron porosity; the water saturation is obtained by processing by using a preset formula based on the real formation porosity and the resistivity; the hydrate saturation is obtained by backstepping by using the gas correction principle based on the density data, the real formation porosity and the water saturation; and the gas saturation of the target formation is obtained by backstepping based on the water saturation and the hydrate saturation. The embodiment of the present application excludes the dependence on acoustic velocity logging, and the more reliable formation porosity is obtained by the joint use of the density and the neutron porosity. Secondly, the embodiment of the present application only uses the three most conventional and necessary logging data of density, neutron and resistivity, does not need the expensive and not popular nuclear magnetic resonance logging, greatly reduces the application threshold and cost of the method, and has excellent universality. Finally, the technical core of the embodiment of the present application is deduced and inverted based on the physical logging response equation and the classical theoretical formula, the linear regression dependence on the core analysis data of a specific area is abandoned, the theoretical basis of the method is more solid, the application range is no longer limited to the cored area, and the method can be popularized to new exploration areas.

[0085] The embodiments described in the embodiments of the present application are used to more clearly illustrate the technical solutions of the embodiments of the present application, and do not constitute a limitation on the technical solutions provided by the embodiments of the present application. It can be understood by those skilled in the art that, with the evolution of technology and the appearance of new application scenarios, the technical solutions provided by the embodiments of the present application are also applicable to similar technical problems.

[0086] Those skilled in the art can understand that the technical solutions shown in the figures do not constitute a limitation on the embodiments of the present application, and can include more or fewer steps than the figures, or combine certain steps or different steps.

[0087] The system embodiments described above are only schematic, and the units described as separate components can or can not be physically separate, that is, can be located in one place or distributed on multiple network units. Part or all of the modules can be selected according to actual needs to achieve the purpose of the embodiments.

[0088] Those skilled in the art can understand that all or some steps in the above disclosed method, the functions of the modules / units in the system and the device can be implemented as software, firmware, hardware and their appropriate combinations.

[0089] The terms "first", "second", "third", "fourth", and the like in the description and in the claims of this application, if any, are used for distinguishing between similar elements and not necessarily for describing a particular sequential or chronological order. It is to be understood that the use of the terms so termed is interchangeable under appropriate circumstances such that the embodiments of the application described herein are, for example, capable of orderly or chronological mundane operation, reverse order operation, based on completion of some desired or other convenient events, or based on other modification that can be wished to those with average skill in the art. Additionally, the terms "comprising", "having", "including", and "containing" are to be construed as open-ended terms (i.e., meaning "including, but not limited to", "comprising, but not limited to", "having, but not limited to", or "including, but not limited to") unless otherwise noted. Recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein and each separate value is incorporated into the specification as if it were individually recited herein. The use of any of the following terms "coupled", "connected", or "communicatively coupled", means the elements so connected are electrically or physically connected in some way and do not necessarily mean a direct electrical, physical or communicative connection unless otherwise indicated herein.

[0090] It should be understood that, in the application, "at least one" means one or more, and "multiple" means two or more. "And / or" is used to describe the relationship between associated objects, which means that there can be three relationships, for example, "A and / or B" can mean that there are three cases: only A, only B, and A and B at the same time, where A and B can be singular or plural. The character " / " generally represents an "or" relationship between the associated objects. "At least one of the following" or similar expressions means any combination of these items, including any combination of single or multiple items. For example, at least one of a, b or c can mean a, b, c, "a and b", "a and c", "b and c", or "a and b and c", where a, b, and c can be single or multiple.

[0091] In several embodiments provided by the application, it should be understood that the disclosed system and method can be implemented in other ways. For example, the above-described system embodiments are only illustrative, for example, the division of the above-mentioned units is only a logical functional division, and actual implementation can have another division manner, for example, multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. In addition, the coupling or direct coupling or communication connection between the displayed or discussed each other can be through some interface, indirect coupling or communication connection between the system or unit, which can be electrical, mechanical or other forms.

[0092] The units described above as separate components can or can not be physically separate, and the components shown as units can or can not be physical units, that is, they can be located in one place, or they can be distributed on multiple network units. Part or all of the units can be selected according to actual needs to achieve the purpose of the embodiment.

[0093] In addition, each function unit in each embodiment of the present application can be integrated in one processing unit, or each unit can be physically present separately, or two or more units can be integrated in one unit. The integrated unit can be realized in the form of hardware or in the form of a software function unit.

[0094] If the integrated unit is realized in the form of a software function unit and sold or used as an independent product, it can be stored in a computer readable storage medium. Based on such understanding, the technical solutions of the present application, essentially or the part that contributes to the prior art, or all or part of the technical solutions can be embodied in the form of a software product. The computer software product is stored in a storage medium, and includes multiple instructions for causing a computer device (which can be a personal computer, a server, or a network device, etc.) to perform all or part of the steps of the methods in each embodiment of the present application. The foregoing storage medium includes: a U disk, a mobile hard disk, a read-only memory (ROM), a random access memory (RAM), a magnetic disk or an optical disk, and various program storage media.

[0095] The preferred embodiments of the embodiments of the present application are described above with reference to the accompanying drawings, and are not limited to the scope of the embodiments of the present application. Any modification, equivalent replacement and improvement made by those skilled in the art without departing from the scope and essence of the embodiments of the present application shall be within the scope of the embodiments of the present application.

Claims

1. A method for determining the saturation of a co-stored natural gas hydrate and associated gas reservoir, characterized by, The method comprises the following steps: Obtaining acquisition parameters of a target formation, the acquisition parameters comprising density data, neutron porosity and resistivity; Processing density porosity based on the density data by using a density logging response equation, and converting the density porosity and the neutron porosity to obtain real formation porosity; Processing water saturation based on the real formation porosity and the resistivity by using a preset formula; Processing hydrate saturation based on the density data, the real formation porosity and the water saturation by using a gas correction principle; Processing gas saturation of the target formation based on the water saturation and the hydrate saturation.

2. The method of claim 1, wherein, The density data comprises density logging values, matrix density and formation water density, and the density porosity is processed based on the density data by using a density logging response equation, comprising the following steps: Obtaining the density porosity according to the ratio of the difference between the density logging values and the matrix density to the difference between the formation water density and the matrix density; Wherein, the expression of the density porosity is: ; wherein denotes the density porosity; denotes the density log value; denotes the matrix density; denotes the formation water density.

3. The method of claim 1, wherein, The density porosity and the neutron porosity are converted to obtain real formation porosity, comprising the following steps: Squaring the mean of the square of the density porosity and the square of the neutron porosity to obtain the real formation porosity; Wherein, the expression of the real formation porosity is: ; wherein represents true formation porosity; represents density porosity; represents neutron porosity.

4. The method of claim 1, wherein, The resistivity comprises formation water resistivity and formation resistivity, the preset formula comprises Archie formula, and the water saturation is processed based on the real formation porosity and the resistivity by using the preset formula, comprising the following steps: Taking the product of the formation water resistivity and a preset lithology coefficient as a first value; Taking a preset porosity index as an exponent of the real formation porosity to perform power operation, and taking the product of the power operation result and the formation resistivity as a second value; Taking the ratio of the first value and the second value as a target value; Taking a preset saturation index as a root index to perform square root operation on the target value to obtain the water saturation; Wherein, the expression of the water saturation is: ; wherein, represents water saturation; represents saturation exponent; and represents lithology factor; represents formation water resistivity; represents true formation porosity; represents pore index; represents formation resistivity.

5. The method of claim 4, wherein, The resistivity further comprises pure rock resistivity of saturated water, and the method further comprises the following steps: Obtaining a formation factor according to the ratio of the pure rock resistivity of saturated water to the formation water resistivity; Converting the porosity index according to the relationship between the formation factor and the real formation porosity in a double logarithmic coordinate; Wherein, the expression of the formation factor and the relationship between the formation factor and the real formation porosity is: ; wherein represents a formation factor; represents a pure rock resistivity of the saturated water; represents a formation water resistivity.

6. The method of claim 1, wherein, The density data comprises density logging values, matrix density, formation water density, hydrate density and associated gas density, and the hydrate saturation is processed based on the density data, the real formation porosity and the water saturation by using a gas correction principle, comprising the following steps: The hydrate saturation is obtained based on the gas-containing correction principle and the relationship between the hydrate saturation and the density data, the real formation porosity and the water saturation, and then the hydrate saturation is calculated based on the density data, the real formation porosity and the water saturation; The expression of the gas-containing correction principle is as follows: ; The expression of the hydrate saturation is as follows: ; wherein, , , , and denote, in sequence, the density log value, the matrix density, the formation water density, the hydrate density and the associated gas density; denotes the true formation porosity; denotes the water saturation; denotes the hydrate saturation.

7. The method according to any one of claims 1 to 6, characterized in that, The gas saturation of the target formation is obtained based on the water saturation and the hydrate saturation, and the gas saturation of the target formation is obtained by subtracting the water saturation and the hydrate saturation from 1. The system comprises:

8. A natural gas hydrate and associated gas co-storage reservoir saturation determination system characterized by, A data acquisition module is configured to acquire acquisition parameters of a target formation, the acquisition parameters comprising density data, neutron porosity and resistivity; A first data processing module is configured to obtain a density porosity based on the density data by using a density logging response equation, and to obtain a real formation porosity by combining the density porosity and the neutron porosity; A second data processing module is configured to obtain a water saturation based on the real formation porosity and the resistivity by using a preset formula; A third data processing module is configured to obtain a hydrate saturation based on the density data, the real formation porosity and the water saturation by using a gas-containing correction principle; A fourth data processing module is configured to obtain a gas saturation of the target formation based on the water saturation and the hydrate saturation. The electronic device comprises a memory and a processor, the memory stores a computer program, and the processor implements the method of any one of claims 1 to 7 when executing the computer program.

9. An electronic device, comprising: The computer program is executed by the processor to implement the method of any one of claims 1 to 7.

10. A computer program product comprising a computer program, characterized in that, ​

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