A method and system for determining the resource volume of natural gas hydrates

Abstract

The present invention provides a method and system for determining the amount of natural gas hydrate resources. The method includes: obtaining the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone of the target area, as well as the natural gas hydrate volume factor, the thickness and area of the sedimentary rock layer where the conventional oil and gas resources are located, and the natural gas volume factor; obtaining the proportion of gaseous hydrocarbons in the target area; determining the proportion of natural gas hydrates in the conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone, as well as the natural gas hydrate volume factor, the thickness and area of the sedimentary rock layer where the conventional oil and gas resources are located, as well as the natural gas volume factor, and the proportion of gaseous hydrocarbons; obtaining the amount of conventional oil and natural gas resources and the amount of conventional heavy oil and asphalt resources in the target area; determining the amount of natural gas hydrate resources in the target area based on the amount of conventional oil and natural gas resources, the amount of conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in the conventional oil and gas resources.

Description

Technical Field

[0001] The present invention relates to the technical field of natural gas hydrate exploration, and in particular to a method and system for determining the amount of natural gas hydrate resources. Background Art

[0002] Natural gas hydrates (NGH) are considered a new resource that could replace traditional oil and gas in the future. Assessing their global resource potential has long been a matter of concern. However, due to uncertainties in the gas hydrate stability zone (GHSZ) and other resource assessment parameters, research on global NGH resource assessment has been slow, presenting a pressing challenge. Previous studies have published at least 29 assessments of global NGH resources based on different research areas and assessment methods, with estimates varying by as much as 10,000-fold. To further reduce the uncertainty in global NGH resource assessments, previous researchers have proposed various methods, ranging from analyzing the key factors controlling the distribution of the hydrate stability zone to developing precise observation models and function calculations to reduce the uncertainty in global NGH resource assessments. Significant progress has been made.

[0003] From 1973 to 1981, based on very little real data and imaginary parameters, some scholars believed that the maximum global gas hydrate resources were estimated to be more than 1.67×10 18 m 3Scholars are highly optimistic about the potential of natural gas hydrates. In 1982, researchers began studying the global marine environment for natural gas hydrate reserves and determined that hydrates are not present in areas with water depths less than 500 meters. This reduced the estimated global natural gas hydrate reserves by half. In 1991, researchers began applying geological surveys and exploration to predict favorable areas for natural gas hydrates in marine environments. Seafloor simulated reflectors (BSRs), representing anomalies reflected in seismic profiles between gas hydrate-bearing strata within the seafloor and underlying non-hydrate-bearing strata, are used to pinpoint the presence of gas hydrates. This has further reduced the estimated global gas hydrate resource to one-quarter of the original estimate. In 1999, researchers revealed that the degradation of organic matter in sedimentary strata is the source of gas in gas hydrate reservoirs. This gas and water form a "cage-like" structure of solid combustible ice, which remains stable only under specific high-pressure and low-temperature conditions. This defined the gas hydrate stability zone as the gas hydrate stability zone (GHSZ) within Earth's polar regions, plateau permafrost, and deep-sea sedimentary basins, further reducing the global gas hydrate resource estimate to one-third. From 2009 to 2016, researchers proposed the concept of recoverable hydrate resources, limiting them to hydrates concentrated in highly porous and permeable formations, such as sandstones, conglomerates, and fractured mudstones. Further assessments revealed that recoverable resources account for less than 18% of the global total. In recent years, with the advancement of physical simulation experiments and field trials, the technical recovery rate of natural gas hydrates has been determined to be 15% to 70%, with an average of 30%. The global recoverable natural gas hydrate resources have further shrunk to 1 / 3 of the original amount.

[0004] The above assessments reveal that, over time, advances in scientific and technological research and improved methodologies appear to have led to a gradual decrease in the estimated potential NGH resources. When assessing NGH resources, due to their high-pressure, low-temperature distribution, it is unavoidable to determine the area and thickness of the GHSZ, as well as data such as the porosity, permeability, and hydrate saturation of the GHSZ formations. Generally speaking, previous studies have relied on measured or simulated data from a specific region. By calculating the volume, porosity, permeability, and hydrate saturation of the GHSZ formations within the study area, they have calculated the potential natural gas hydrate resources in that region. These studies have used methods such as extrapolation of field data or model function calculations to estimate global natural gas hydrate potential. However, the variability of these data leads to inaccurate and significant discrepancies between assessments, and with current technology and exploration levels, it is difficult to improve the accuracy of these assessments. Furthermore, previous studies have considered all hydrates within the GHSZ as potential resources, failing to distinguish between dispersed hydrates in mudstones and enriched hydrate resources within highly porous and permeable reservoirs, resulting in inflated estimates.

[0005] Given current technological advancements and exploration efforts, an accurate assessment of global natural gas hydrate resources is essentially impossible. Research has found that gas generated by the degradation of organic matter in formations beneath the GHSZ is a significant source of gas in hydrates within the GHSZ. This suggests that after gas is expelled from deep source rocks within oil and gas-rich basins, it can migrate to the hydrate stability zone and form "cage-like" hydrates with water. One-third of the 13 hydrate exploration wells worldwide have confirmed that the gas in these hydrates originates from the degradation of organic matter within deep source rocks, demonstrating that natural gas hydrates, like conventional oil and gas resources, represent a unique class within the global oil and gas system. Natural gas hydrates share many characteristics with conventional oil and gas resources. For example, both form within free-flowing fields, are driven by buoyancy, their hydrocarbons are derived from the degradation of organic matter in source rocks, and both reservoirs require high porosity and high permeability. This allows the evaluation of natural gas hydrate resources to be analogous to the evaluation methods and approaches for conventional oil and gas resources. Based on this, the present invention proposes a method for evaluating natural gas hydrate resources based on the analogy with conventional oil and gas resources. Summary of the Invention

[0006] In order to solve the problem of difficult and low-precision evaluation of natural gas hydrate resources and provide important technical support for the evaluation of hydrate resource potential and energy prospects, the purpose of the present invention is to provide a method and system for determining the amount of natural gas hydrate resources.

[0007] In order to achieve the above objectives, the present invention provides the following four technical solutions.

[0008] In a first aspect, the present invention provides a method for determining the amount of natural gas hydrate resources, wherein the method comprises:

[0009] Obtain the thickness and area of the sedimentary rock layer in the gas hydrate stability zone in the target area and the gas hydrate volume factor;

[0010] Obtain the thickness and area of the sedimentary rock layers and the natural gas volume factor of the conventional oil and gas resources in the target area; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy;

[0011] Obtaining the proportion of gaseous hydrocarbons in the target area; wherein the proportion of gaseous hydrocarbons refers to the proportion of gaseous hydrocarbons in the discharged hydrocarbons;

[0012] Determine the proportion of natural gas hydrates in conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layers in the natural gas hydrate stability zone and the natural gas hydrate volume factor, the thickness and area of the sedimentary rock layers in which conventional oil and gas resources are located and the natural gas volume factor, and the proportion of gaseous hydrocarbons in the target area;

[0013] Obtain the conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area; wherein, conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have not been biodegraded; conventional heavy oil and asphalt resources refer to heavy oil and asphalt resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have been biodegraded;

[0014] The amount of natural gas hydrate resources in the target area is determined based on the amount of conventional oil and gas resources, conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in conventional oil and gas resources in the target area.

[0015] According to a preferred embodiment of the first aspect, obtaining the proportion of gaseous hydrocarbons in the target area includes:

[0016] The first ratio is the ratio of the amount of gas generated by the target area's organic matter type III source rock during the biochemical gas generation stage (Ro<0.5%) to the total amount of hydrocarbons generated; the second ratio is the ratio of the amount of gas to the total amount of hydrocarbons in the proven conventional oil and gas reservoirs in the target area;

[0017] The third ratio is obtained by obtaining the weighted average of the ratios of gaseous hydrocarbons generated by source rocks of organic matter types I, II, and III in the free dynamic field of the target area during the biogenic gas generation stage and the thermal gas generation stage to the total hydrocarbons generated;

[0018] Determining the gaseous hydrocarbon ratio of the target area based on the first ratio, the second ratio, and the third ratio; wherein the gaseous hydrocarbon ratio of the target area is less than or equal to the first ratio and greater than or equal to the second ratio;

[0019] Preferably, the third ratio is used as the initial value of the gaseous hydrocarbon proportion in the target area, and the first ratio and the second ratio are used to correct the initial value of the gaseous hydrocarbon proportion in the target area to obtain the gaseous hydrocarbon proportion in the target area; wherein, when the initial value of the gaseous hydrocarbon proportion in the target area is less than or equal to the first ratio and greater than or equal to the second ratio, the gaseous hydrocarbon proportion in the target area is the initial value of the gaseous hydrocarbon proportion in the target area; when the initial value of the gaseous hydrocarbon proportion in the target area is greater than the first ratio, the gaseous hydrocarbon proportion in the target area is the first ratio; when the initial value of the gaseous hydrocarbon proportion in the target area is less than the second ratio, the gaseous hydrocarbon proportion in the target area is the second ratio.

[0020] According to a preferred embodiment of the first aspect, the proportion of natural gas hydrates in conventional oil and gas resources is determined by the following formula:

[0021]

[0022] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; B ghB is the gas hydrate volume factor, which represents the ratio of the volume of methane hydrate under standard surface conditions to the volume of gas hydrate under reservoir conditions, and the unit is dimensionless; g A is the natural gas volume factor, which represents the ratio of the natural gas volume under standard surface conditions to the natural gas volume under reservoir conditions, and the unit is dimensionless; GHSZ is the area of the sedimentary rock layer in the gas hydrate stability zone, unit 10 6 km 2 ;H GHSZ is the thickness of the sedimentary rock layer in the gas hydrate stability zone, in m; A conv is the area of sedimentary rock layers where conventional oil and gas resources are located, unit 10 6 km 2 ;H conv is the thickness of the sedimentary rock layer where conventional oil and gas resources are located, in m; g is the proportion of gaseous hydrocarbons, in %.

[0023] According to a preferred embodiment of the first aspect, the amount of natural gas hydrate resources is determined using a natural gas hydrate resource determination model; wherein the natural gas hydrate resource determination model is a calculation model of the amount of natural gas hydrate resources with respect to the proportion of natural gas hydrates in conventional oil and gas resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources;

[0024] Preferably, the natural gas hydrate resource determination model is:

[0025]

[0026] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit: 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit: 10 12 m 3 .

[0027] In a second aspect, the present invention provides a system for determining the amount of natural gas hydrate resources, wherein the system comprises:

[0028] Gas hydrate parameter acquisition module: used to obtain the thickness and area of the sedimentary rock layer in the gas hydrate stability zone in the target area and the gas hydrate volume factor;

[0029] Oil and gas resource parameter acquisition module: used to obtain the thickness and area of the sedimentary rock layer where conventional oil and gas resources are located in the target area, as well as the natural gas volume factor; wherein, conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy;

[0030] Gaseous hydrocarbon ratio acquisition module: used to obtain the gaseous hydrocarbon ratio of the target area; wherein the gaseous hydrocarbon ratio refers to the ratio of gaseous hydrocarbons in the discharged hydrocarbons;

[0031] Gas hydrate proportion acquisition module: used to determine the proportion of gas hydrate in conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layer in the gas hydrate stability zone and the gas hydrate volume factor, the thickness and area of the sedimentary rock layer where the conventional oil and gas resources are located in the target area and the natural gas volume factor, and the proportion of gaseous hydrocarbons in the target area;

[0032] Conventional Energy Acquisition Module: used to acquire conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area; conventional oil and gas resources refer to non-biodegraded oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy; conventional heavy oil and asphalt resources refer to biodegraded heavy oil and asphalt resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy;

[0033] Natural Gas Hydrate Resource Acquisition Module: This module is used to determine the amount of natural gas hydrate resources in a target area based on the amount of conventional oil and gas resources, conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in conventional oil and gas resources in the target area.

[0034] According to a preferred embodiment of the second aspect, the gaseous hydrocarbon proportion acquisition module includes:

[0035] The first ratio acquisition submodule is used to obtain the ratio of the amount of gas generated by the source rock with organic matter type III in the target area during the biochemical gas generation stage (Ro<0.5%) to the total amount of hydrocarbons generated, which is the first ratio;

[0036] The second ratio acquisition submodule is used to obtain the ratio of the gas volume to the total hydrocarbon volume in the proven conventional oil and gas reservoirs in the target area, which is the second ratio;

[0037] The third ratio acquisition submodule is used to obtain the weighted average of the ratios of gaseous hydrocarbons generated by source rocks of organic matter types I, II, and III in the free dynamic field of the target area during the biogenic gas generation stage and the thermal gas generation stage to the total hydrocarbons generated, which is the third ratio;

[0038] A gaseous hydrocarbon ratio determination submodule is configured to determine the gaseous hydrocarbon ratio of the target area based on the first ratio, the second ratio, and the third ratio; wherein the gaseous hydrocarbon ratio of the target area is less than or equal to the first ratio and greater than or equal to the second ratio;

[0039] Preferably, the gaseous hydrocarbon proportion determination submodule is used to use the third ratio as the initial value of the gaseous hydrocarbon proportion of the target area, and use the first ratio and the second ratio to correct the initial value of the gaseous hydrocarbon proportion of the target area to obtain the gaseous hydrocarbon proportion of the target area; wherein, when the initial value of the gaseous hydrocarbon proportion of the target area is less than or equal to the first ratio and greater than or equal to the second ratio, the gaseous hydrocarbon proportion of the target area is the initial value of the gaseous hydrocarbon proportion of the target area; when the initial value of the gaseous hydrocarbon proportion of the target area is greater than the first ratio, the gaseous hydrocarbon proportion of the target area is the first ratio; when the initial value of the gaseous hydrocarbon proportion of the target area is less than the second ratio, the gaseous hydrocarbon proportion of the target area is the second ratio.

[0040] According to a preferred embodiment of the second aspect, the natural gas hydrate proportion acquisition module determines the proportion of natural gas hydrate in conventional oil and gas resources by the following formula:

[0041]

[0042] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; B gh B is the gas hydrate volume factor, which represents the ratio of the volume of methane hydrate under standard surface conditions to the volume of gas hydrate under reservoir conditions, and the unit is dimensionless; g A is the natural gas volume factor, which represents the ratio of the natural gas volume under standard surface conditions to the natural gas volume under reservoir conditions, and the unit is dimensionless; GHSZ is the area of the sedimentary rock layer in the gas hydrate stability zone, unit 10 6 km 2 ;H GHSZ is the thickness of the sedimentary rock layer in the gas hydrate stability zone, in m; A conv is the area of sedimentary rock layers where conventional oil and gas resources are located, unit 10 6 km 2 ;H conv is the thickness of the sedimentary rock layer where conventional oil and gas resources are located, in m; g is the proportion of gaseous hydrocarbons, in %.

[0043] According to a preferred embodiment of the second aspect, the gas hydrate resource quantity acquisition module determines the gas hydrate resource quantity using a gas hydrate resource quantity determination model; wherein the gas hydrate resource quantity determination model is a calculation model of the gas hydrate resource quantity with respect to the proportion of gas hydrates in conventional oil and gas resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources;

[0044] Preferably, the natural gas hydrate resource determination model is:

[0045]

[0046] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 .

[0047] In a third aspect, the present invention provides an electronic device comprising a processor, a memory, and a computer program stored in the memory and executable on the processor, wherein when the processor executes the program, the steps of the method for determining the amount of natural gas hydrate resources are implemented.

[0048] In a fourth aspect, the present invention provides a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the steps of the method for determining the amount of natural gas hydrate resources.

[0049] The technical solution provided by the present invention effectively solves the problem of evaluating natural gas hydrate resources, and solves the problem of low reliability of natural gas hydrate resource assessment caused by low exploration level, low exploration technology and lack of exploration data in the past. It can obtain natural gas hydrate resources more objectively and accurately, and has great guiding significance for the study of natural gas hydrate resource potential and energy prospects. BRIEF DESCRIPTION OF THE DRAWINGS

[0050] Figure 1 Flowchart of a method for determining natural gas hydrate resources in one embodiment.

[0051] Figure 2 A framework diagram of a system for determining natural gas hydrate resources in one embodiment.

[0052] Figure 3 is the area A of the sedimentary rock layer in the global natural gas hydrate stability zone in Example 1 GHSZ Distribution statistics chart.

[0053] Figure 4 is the thickness H of the sedimentary rock layer in the global natural gas hydrate stability zone in Example 1 GHSZ Distribution statistics chart.

[0054] Figure 5 This is a statistical diagram of the distribution of the proportion of gaseous hydrocarbons in global natural gas hydrates g in Example 1.

[0055] Figure 6 This is a graph showing the ratio of gas to total hydrocarbons generated for source rocks of different organic matter types in Example 1 during the biochemical gas generation stage (Ro<0.5%).

[0056] Figure 7 This is a diagram of the ratio of gas to total hydrocarbons in the world's proven conventional oil and gas reservoirs in Example 1.

[0057] Figure 8 Figure 2 shows the ratio of gaseous hydrocarbons to total hydrocarbons in the hydrocarbon generation of source rocks with type I, type II, and type III kerogen in a free dynamic field during the biogenic and thermogenic gas generation stages. DETAILED DESCRIPTION

[0058] To make the purpose, technical solutions, and advantages of the embodiments of the present invention more clear, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts are within the scope of protection of the present invention.

[0059] The inventors incorporated natural gas hydrate resources into the global oil and gas system, conducting unified analysis and research. They established a unified model and mass balance equation for NGH resources and conventional oil and gas resources. By comprehensively comparing conventional oil and gas evaluation parameters with 29 previous natural gas hydrate assessment results, they proposed a method for evaluating natural gas hydrate resources based on conventional oil and gas resource analogy. This method addresses the difficulty and low accuracy of global natural gas hydrate resource assessment and provides new insights into the potential and energy prospects of hydrate resources. The following describes the technical solutions provided by the present invention through the enumeration of several specific embodiments.

[0060] See also Figure 1 A specific embodiment of the present invention provides a method for determining the amount of natural gas hydrate resources, wherein the method comprises:

[0061] Step S1: Obtaining the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone in the target area and the natural gas hydrate volume factor;

[0062] Step S2: Obtaining the thickness and area of the sedimentary rock layer where conventional oil and gas resources are located in the target area, as well as the natural gas volume factor; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy;

[0063] Step S3: Obtaining the proportion of gaseous hydrocarbons in the target area; wherein the proportion of gaseous hydrocarbons refers to the proportion of gaseous hydrocarbons in the discharged hydrocarbons;

[0064] Step S4: determining the proportion of natural gas hydrates in conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone and the natural gas hydrate volume factor, the thickness and area of the sedimentary rock layer where conventional oil and gas resources are located in the target area and the natural gas volume factor, and the proportion of gaseous hydrocarbons in the target area;

[0065] Step S5: Obtaining the conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have not been biodegraded; and the conventional heavy oil and asphalt resources refer to heavy oil and asphalt resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have been biodegraded;

[0066] Step S6: Determine the amount of natural gas hydrate resources in the target area based on the amount of conventional oil and gas resources, the amount of conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in conventional oil and gas resources in the target area.

[0067] The above-mentioned method for determining the amount of natural gas hydrate resources solves the drawbacks of insufficient geological theory and large errors in evaluation methods in the past. It has achieved the following advantages: (1) sufficient geological basis and high credibility; (2) distinct technical features and high accuracy; (3) complete and clear ideas and strong innovation; (4) easy access to data and strong operability.

[0068] In one embodiment, step S3, obtaining the percentage of gaseous hydrocarbons in the target area, includes:

[0069] Step S31: Obtaining the ratio of the amount of gas generated by the source rock of type III organic matter in the target area during the biochemical gas generation stage (Ro<0.5%) to the total amount of hydrocarbons generated, which is the first ratio; the first ratio is the possible upper limit of the parameter gaseous hydrocarbon ratio;

[0070] Step S32: obtaining the ratio of the gas volume to the total hydrocarbon volume in the proven conventional oil and gas reservoirs in the target area as a second ratio; the second ratio is a possible lower limit value of the parameter gaseous hydrocarbon ratio;

[0071] Step S33: obtaining a weighted average value of the ratios of gaseous hydrocarbons generated by source rocks of organic matter types I, II, and III in the free dynamic field of the target area during the biogenic gas generation stage and the thermal gas generation stage to the total hydrocarbons generated, which is the third ratio;

[0072] Step S34: determining the gaseous hydrocarbon ratio of the target area based on the first ratio, the second ratio, and the third ratio; wherein the gaseous hydrocarbon ratio of the target area is less than or equal to the first ratio and greater than or equal to the second ratio;

[0073] For example, the third ratio is used as the initial value of the gaseous hydrocarbon proportion in the target area, and the initial value of the gaseous hydrocarbon proportion in the target area is corrected using the first ratio and the second ratio to obtain the gaseous hydrocarbon proportion in the target area; wherein, when the initial value of the gaseous hydrocarbon proportion in the target area is less than or equal to the first ratio and greater than or equal to the second ratio, the gaseous hydrocarbon proportion in the target area is the initial value of the gaseous hydrocarbon proportion in the target area; when the initial value of the gaseous hydrocarbon proportion in the target area is greater than the first ratio, the gaseous hydrocarbon proportion in the target area is the first ratio; when the initial value of the gaseous hydrocarbon proportion in the target area is less than the second ratio, the gaseous hydrocarbon proportion in the target area is the second ratio;

[0074] For example, the ratio of gaseous hydrocarbons generated by type I organic matter source rocks in the biogenic gas generation stage to the total hydrocarbons generated, the ratio of gaseous hydrocarbons generated by type I organic matter source rocks in the thermogenic gas generation stage to the total hydrocarbons generated, the ratio of gaseous hydrocarbons generated by type II organic matter source rocks in the biogenic gas generation stage to the total hydrocarbons generated, the ratio of gaseous hydrocarbons generated by type II organic matter source rocks in the thermogenic gas generation stage to the total hydrocarbons generated, the ratio of gaseous hydrocarbons generated by type III organic matter source rocks in the biogenic gas generation stage to the total hydrocarbons generated, and the ratio of gaseous hydrocarbons generated by type III organic matter source rocks in the thermogenic gas generation stage to the total hydrocarbons generated are obtained respectively in the free dynamic field of the target area, and the third ratio is obtained by performing weighted average on the above ratios.

[0075] In one embodiment, in step S4, the proportion of natural gas hydrates in conventional oil and gas resources is determined by the following formula:

[0076]

[0077] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; B gh B is the gas hydrate volume factor, which represents the ratio of the volume of methane hydrate under standard surface conditions to the volume of gas hydrate under reservoir conditions, and the unit is dimensionless; g A is the natural gas volume factor, which represents the ratio of the natural gas volume under standard surface conditions to the natural gas volume under reservoir conditions, and the unit is dimensionless; GHSZ is the area of the sedimentary rock layer in the gas hydrate stability zone, unit 10 6 km2 ;H GHSZ is the thickness of the sedimentary rock layer in the gas hydrate stability zone, in m; A conv is the area of sedimentary rock layers where conventional oil and gas resources are located, unit 10 6 km 2 ;H conv is the thickness of the sedimentary rock layer where conventional oil and gas resources are located, in m; g is the proportion of gaseous hydrocarbons, in %.

[0078] In one embodiment, step S6, the amount of natural gas hydrate resources is determined using a natural gas hydrate resource determination model; wherein the natural gas hydrate resource determination model is a calculation model for the amount of natural gas hydrate resources with respect to the proportion of natural gas hydrates in conventional oil and gas resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources;

[0079] Furthermore, the natural gas hydrate resource determination model is:

[0080]

[0081] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;

[0082] The natural gas hydrate resource determination model is preferably established in the following manner:

[0083] Like other oil and gas resources, natural gas hydrates derive their hydrocarbons from the degradation of deep organic matter. Therefore, natural gas hydrate resources are included in the oil and gas system. The oil and gas system includes all surface source rocks and the associated hydrocarbon migration and accumulation processes. The oil and gas resource types included in the oil and gas system include conventional oil and gas resources, unconventional oil and gas resources, and shale oil and gas resources. Based on the mass balance principle, a correlation model is established between conventional oil and gas resources, unconventional oil and gas resources, shale oil and gas resources, and the total oil and gas resources generated by the source rocks within the oil and gas system:

[0084] Q C +Q U +Q S ≤≤Q P

[0085] Where QC is the conventional oil and gas resources; Q U is the amount of unconventional oil and gas resources; Q S is the shale oil and gas resources, Q P is the total generated oil and gas resources;

[0086] Natural gas hydrates share the same characteristics as conventional oil and gas resources, conventional heavy oil, and asphalt resources in terms of hydrocarbon sources, migration and accumulation dynamics and processes, and reservoir characteristics. Furthermore, natural gas hydrates are only preserved within stable zones of high pressure and low temperature. Therefore, natural gas hydrates can be considered a special type of conventional oil and gas resource that accumulates in reservoirs under high pressure and low temperature conditions. Based on this, a correlation model for natural gas hydrate resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources is established:

[0087] Q C =Q C1 +Q C2 +Q C3 ≤Q EC

[0088] Where Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;Q EC It is the hydrocarbon resource volume (in gas equivalent) discharged by source rocks above the lower limit of buoyancy accumulation and within the free dynamic field, unit, 10 12 m 3 ;Q C is the conventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ;

[0089] Based on the correlation models of natural gas hydrate resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources, a unified model and mass balance equation between natural gas hydrate resources and conventional oil and gas resources are established:

[0090] Q C1 =Q C -Q C2 -Q C3 =f×Q C

[0091] Where Q C1is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;Q EC The hydrocarbon resources (in gas equivalent) discharged by source rocks above the lower limit of buoyancy accumulation and within the free dynamic field, unit 10 12 m 3 ;Q C is the conventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ; f is the proportion of natural gas hydrates in conventional oil and gas resources, unit: %;

[0092] Based on the unified model and mass balance equation between natural gas hydrate resources and conventional oil and gas resources, a natural gas hydrate resource determination model is established as follows:

[0093]

[0094] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;

[0095] In short, the above-mentioned natural gas hydrate resource determination model starts from the oil and gas system and conducts a unified analysis and model construction of three types of conventional oil and gas resources (natural gas hydrate resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources) generated by organic matter, within a free dynamic field, and driven by buoyancy. It is established based on the principle of material balance. The above-mentioned natural gas hydrate resource determination model can reflect the mass balance relationship between natural gas hydrate resources and conventional oil and gas resources, and conventional heavy oil and asphalt resources, and can achieve a reliable evaluation of natural gas hydrate resources in the target area (including natural gas hydrate resources in the global region).

[0096] In one embodiment, step S5, obtaining the conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area is achieved by:

[0097] Based on expert assessments in the fields of petroleum geology and exploration and data from authoritative petroleum institutions worldwide, the conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area are determined.

[0098] In one embodiment, step S1, obtaining the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone in the target area and the natural gas hydrate volume factor is achieved by:

[0099] Based on the published results of gas hydrate resource assessment in the target area, the thickness and area of the sedimentary rock layer in the gas hydrate stability zone in the target area and the gas hydrate volume factor are determined through mathematical and statistical analysis methods.

[0100] In one embodiment, step S2, obtaining the thickness and area of the sedimentary rock layer where the conventional oil and gas resources in the target area are located and the natural gas volume factor is achieved by:

[0101] Based on authoritative data from the oil and gas industry in the target area, mathematical and statistical analysis methods are used to determine the thickness and area of the sedimentary rock layers where conventional oil and gas resources are located, as well as the natural gas volume factor.

[0102] The embodiment of the present invention also provides a specific implementation of a system for determining the amount of natural gas hydrate resources, which is used to implement the above-mentioned method embodiment for determining the amount of natural gas hydrate resources. Figure 2 , the system comprises:

[0103] The natural gas hydrate parameter acquisition module 21 is used to obtain the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone in the target area and the natural gas hydrate volume factor;

[0104] Oil and gas resource parameter acquisition module 22: used to obtain the thickness and area of the sedimentary rock layer where the conventional oil and gas resources in the target area are located, as well as the natural gas volume factor; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy;

[0105] The gaseous hydrocarbon ratio acquisition module 23 is used to obtain the gaseous hydrocarbon ratio of the target area; wherein the gaseous hydrocarbon ratio refers to the ratio of gaseous hydrocarbons in the discharged hydrocarbons;

[0106] The natural gas hydrate proportion acquisition module 24 is used to determine the proportion of natural gas hydrates in conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone and the natural gas hydrate volume factor, the thickness and area of the sedimentary rock layer where the conventional oil and gas resources in the target area are located and the natural gas volume factor, and the proportion of gaseous hydrocarbons in the target area.

[0107] Conventional energy acquisition module 25: used to acquire conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area; wherein, conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have not been biodegraded; conventional heavy oil and asphalt resources refer to heavy oil and asphalt resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have been biodegraded;

[0108] The natural gas hydrate resource acquisition module 26 is used to determine the natural gas hydrate resource volume in the target area based on the conventional oil and natural gas resource volume, conventional heavy oil and asphalt resource volume, and the proportion of natural gas hydrate in conventional oil and gas resources in the target area.

[0109] In one embodiment, the gaseous hydrocarbon ratio acquisition module 23 includes:

[0110] The first ratio acquisition submodule 231 is used to obtain the ratio of the amount of gas generated by the source rock of type III organic matter in the target area during the biochemical gas generation stage (Ro<0.5%) to the total amount of hydrocarbons generated, which is the first ratio. The first ratio is the possible upper limit of the parameter gaseous hydrocarbon ratio.

[0111] Second ratio acquisition submodule 232: used to obtain the ratio of the gas volume to the total hydrocarbon volume in the proven conventional oil and gas reservoirs in the target area, which is the second ratio; the second ratio is the possible lower limit of the parameter gaseous hydrocarbon ratio;

[0112] The third ratio acquisition submodule 233 is used to obtain the weighted average of the ratios of gaseous hydrocarbons generated by source rocks of organic matter types I, II, and III in the free dynamic field of the target area during the biogenic gas generation stage and the thermal gas generation stage to the total hydrocarbons generated, which is the third ratio;

[0113] The gaseous hydrocarbon ratio determination submodule 234 is configured to determine the gaseous hydrocarbon ratio of the target area based on the first ratio, the second ratio, and the third ratio; wherein the gaseous hydrocarbon ratio of the target area is less than or equal to the first ratio and greater than or equal to the second ratio;

[0114] Furthermore, the gaseous hydrocarbon proportion determination submodule 234 is specifically used to use the third ratio as the initial value of the gaseous hydrocarbon proportion of the target area, and use the first ratio and the second ratio to correct the initial value of the gaseous hydrocarbon proportion of the target area to obtain the gaseous hydrocarbon proportion of the target area; wherein, when the initial value of the gaseous hydrocarbon proportion of the target area is less than or equal to the first ratio and greater than or equal to the second ratio, the gaseous hydrocarbon proportion of the target area is the initial value of the gaseous hydrocarbon proportion of the target area; when the initial value of the gaseous hydrocarbon proportion of the target area is greater than the first ratio, the gaseous hydrocarbon proportion of the target area is the first ratio; when the initial value of the gaseous hydrocarbon proportion of the target area is less than the second ratio, the gaseous hydrocarbon proportion of the target area is the second ratio.

[0115] In one embodiment, the natural gas hydrate proportion acquisition module 24 determines the proportion of natural gas hydrate in conventional oil and gas resources using the following formula:

[0116]

[0117] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; B gh B is the gas hydrate volume factor, which represents the ratio of the volume of methane hydrate under standard surface conditions to the volume of gas hydrate under reservoir conditions, and the unit is dimensionless; g A is the natural gas volume factor, which represents the ratio of the natural gas volume under standard surface conditions to the natural gas volume under reservoir conditions, and the unit is dimensionless; GHSZ is the area of the sedimentary rock layer in the gas hydrate stability zone, unit 10 6 km 2 ;H GHSZ is the thickness of the sedimentary rock layer in the gas hydrate stability zone, in m; A conv is the area of sedimentary rock layers where conventional oil and gas resources are located, unit 10 6 km 2 ;H conv is the thickness of the sedimentary rock layer where conventional oil and gas resources are located, in m; g is the proportion of gaseous hydrocarbons, in %.

[0118] In one embodiment, the natural gas hydrate resource quantity acquisition module 26 determines the natural gas hydrate resource quantity using a natural gas hydrate resource quantity determination model; wherein the natural gas hydrate resource quantity determination model is a calculation model of the natural gas hydrate resource quantity with respect to the proportion of natural gas hydrate in conventional oil and gas resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources;

[0119] Furthermore, the natural gas hydrate resource determination model is:

[0120]

[0121] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; QC1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;

[0122] The natural gas hydrate resource determination model is preferably established in the following manner:

[0123] Like other oil and gas resources, natural gas hydrates derive their hydrocarbons from the degradation of deep organic matter. Therefore, natural gas hydrate resources are included in the oil and gas system. The oil and gas system includes all surface source rocks and the associated hydrocarbon migration and accumulation processes. The oil and gas resource types included in the oil and gas system include conventional oil and gas resources, unconventional oil and gas resources, and shale oil and gas resources. Based on the mass balance principle, a correlation model is established between conventional oil and gas resources, unconventional oil and gas resources, shale oil and gas resources, and the total oil and gas resources generated by the source rocks within the oil and gas system:

[0124] Q C +Q U +Q S ≤Q P

[0125] Where Q C is the conventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ;Q U is the amount of unconventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ;Q S is the shale oil and gas resources (in gas equivalent), unit 10 12 m 3 ;Q P is the total generated oil and gas resources (in gas equivalent), unit 10 12 m 3 ;

[0126] Natural gas hydrates share the same characteristics as conventional oil and gas resources, conventional heavy oil, and asphalt resources in terms of hydrocarbon sources, migration and accumulation dynamics and processes, and reservoir characteristics. Furthermore, natural gas hydrates are only preserved within stable zones of high pressure and low temperature. Therefore, natural gas hydrates can be considered a special type of conventional oil and gas resource that accumulates in reservoirs under high pressure and low temperature conditions. Based on this, a correlation model for natural gas hydrate resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources is established:

[0127] Q C =Q C1 +Q C2 +Q C3 ≤Q EC

[0128] Where Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit: 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;Q EC The hydrocarbon resources (in gas equivalent) discharged by source rocks above the lower limit of buoyancy accumulation and within the free dynamic field, unit 10 12 m 3 ;Q C is the conventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ;

[0129] Based on the correlation models of natural gas hydrate resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources, a unified model and mass balance equation between natural gas hydrate resources and conventional oil and gas resources are established:

[0130] Q C1 =Q C -Q C2 -Q C3 =f×Q C

[0131] Where Q C1 is the natural gas hydrate resource (in gas equivalent), unit: ×10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;Q EC The hydrocarbon resources (in gas equivalent) discharged by source rocks above the lower limit of buoyancy accumulation and within the free dynamic field, unit 10 12 m 3 ;Q C is the conventional oil and gas resources, unit 10 12 m 3 ; f is the proportion of natural gas hydrates in conventional oil and gas resources, unit: %;

[0132] Based on the unified model and mass balance equation between natural gas hydrate resources and conventional oil and gas resources, a natural gas hydrate resource determination model is established as follows:

[0133]

[0134] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;

[0135] In short, the above-mentioned natural gas hydrate resource determination model starts from the oil and gas system and conducts a unified analysis and model construction of three types of conventional oil and gas resources (natural gas hydrate resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources) generated by organic matter, within a free dynamic field, and driven by buoyancy. It is established based on the principle of material balance. The above-mentioned natural gas hydrate resource determination model can reflect the mass balance relationship between natural gas hydrate resources and conventional oil and gas resources, and conventional heavy oil and asphalt resources, and can achieve a reliable evaluation of natural gas hydrate resources in the target area (including natural gas hydrate resources in the global region).

[0136] In one embodiment, the conventional energy acquisition module 25 acquires the conventional oil and natural gas resources and conventional heavy oil and asphalt resources in the target area by:

[0137] Based on expert assessments in the fields of petroleum geology and exploration and data from authoritative petroleum institutions worldwide, the conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area are determined.

[0138] In one embodiment, the natural gas hydrate parameter acquisition module 21 acquires the thickness and area of the sedimentary rock layer and the natural gas hydrate volume factor of the natural gas hydrate stability zone in the target area by the following method:

[0139] Based on the published results of gas hydrate resource assessment in the target area, the thickness and area of the sedimentary rock layer in the gas hydrate stability zone in the target area and the gas hydrate volume factor are determined through mathematical and statistical analysis methods.

[0140] In one embodiment, the oil and gas resource parameter acquisition module 22 acquires the thickness and area of the sedimentary rock layer where the conventional oil and gas resources in the target area are located, as well as the natural gas volume factor, by:

[0141] Based on authoritative data from the oil and gas industry in the target area, mathematical and statistical analysis methods are used to determine the thickness and area of the sedimentary rock layers where conventional oil and gas resources are located, as well as the natural gas volume factor.

[0142] The embodiments of the present invention also provide a specific implementation of an electronic device capable of implementing all steps of the method for determining the amount of natural gas hydrate resources in the above embodiment. The electronic device specifically includes the following contents:

[0143] processors, memories, communication interfaces, and buses;

[0144] The processor, memory, and communication interface communicate with each other via a bus; the communication interface is used to implement information transmission between relevant devices such as a server-side device and a client device; the processor is used to call a computer program in the memory, and when the processor executes the computer program, all steps of the method for determining the amount of natural gas hydrate resources in the above embodiment are implemented. For example, when the processor executes the computer program, the following steps are implemented:

[0145] Step S1: Obtaining the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone in the target area and the natural gas hydrate volume factor;

[0146] Step S2: Obtaining the thickness and area of the sedimentary rock layer where conventional oil and gas resources are located in the target area, as well as the natural gas volume factor; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy;

[0147] Step S3: Obtaining the proportion of gaseous hydrocarbons in the target area; wherein the proportion of gaseous hydrocarbons refers to the proportion of gaseous hydrocarbons in the discharged hydrocarbons;

[0148] Step S4: determining the proportion of natural gas hydrates in conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone and the natural gas hydrate volume factor, the thickness and area of the sedimentary rock layer where conventional oil and gas resources are located in the target area and the natural gas volume factor, and the proportion of gaseous hydrocarbons in the target area;

[0149] Step S5: Obtaining the conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have not been biodegraded; and the conventional heavy oil and asphalt resources refer to heavy oil and asphalt resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have been biodegraded;

[0150] Step S6: Determine the amount of natural gas hydrate resources in the target area based on the amount of conventional oil and gas resources, the amount of conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in conventional oil and gas resources in the target area.

[0151] An embodiment of the present invention further provides a computer-readable storage medium capable of implementing all steps of the method for determining the amount of natural gas hydrate resources in the above embodiment. The computer-readable storage medium stores a computer program. When the computer program is executed by a processor, all steps of the method for determining the amount of natural gas hydrate resources in the above embodiment are implemented. For example, when the processor executes the computer program, the following steps are implemented:

[0152] Step S1: Obtaining the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone in the target area and the natural gas hydrate volume factor;

[0153] Step S2: Obtaining the thickness and area of the sedimentary rock layer where conventional oil and gas resources are located in the target area, as well as the natural gas volume factor; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy;

[0154] Step S3: Obtaining the proportion of gaseous hydrocarbons in the target area; wherein the proportion of gaseous hydrocarbons refers to the proportion of gaseous hydrocarbons in the discharged hydrocarbons;

[0155] Step S4: determining the proportion of natural gas hydrates in conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layer in the natural gas hydrate stability zone and the natural gas hydrate volume factor, the thickness and area of the sedimentary rock layer where conventional oil and gas resources are located in the target area and the natural gas volume factor, and the proportion of gaseous hydrocarbons in the target area;

[0156] Step S5: Obtaining the conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have not been biodegraded; and the conventional heavy oil and asphalt resources refer to heavy oil and asphalt resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have been biodegraded;

[0157] Step S6: Determine the amount of natural gas hydrate resources in the target area based on the amount of conventional oil and gas resources, the amount of conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in conventional oil and gas resources in the target area.

[0158] Example 1

[0159] The following describes the method for determining the amount of natural gas hydrate resources provided by the present invention by taking the world as the target area and determining the amount of natural gas hydrate resources around the world.

[0160] In this embodiment, starting from the perspective of cutting-edge geological theory, in response to the current problems of difficult and low-precision evaluation of global natural gas hydrate resources, especially the low reliability of global natural gas hydrate resource assessment due to low exploration level, low exploration technology and lack of exploration data, a comprehensive analysis is conducted using previous research results and key parameters. Based on the mass balance principle, natural gas hydrate resources are incorporated into the global oil and gas system, and a corresponding unified model and mass balance equation are established to ultimately determine the global natural gas hydrate resources.

[0161] The method used in this embodiment specifically includes the following steps:

[0162] 1. Natural gas hydrate resource determination model; specifically including:

[0163] 1.1. Like other oil and gas resources, natural gas hydrates derive their hydrocarbons from the degradation of deep organic matter. Natural gas hydrate resources are therefore considered part of the oil and gas system. The global oil and gas system encompasses all surface source rocks and the associated hydrocarbon migration and accumulation processes. The oil and gas resource types encompassed by the global oil and gas system include conventional, unconventional, and shale oil and gas resources. Based on the mass balance principle, a correlation model is established between conventional oil and gas resources (conventional oil and gas resources are defined as those generated from organic matter, distributed within a free dynamic field, and driven by buoyancy), unconventional oil and gas resources, and shale oil and gas resources, and the total oil and gas resources generated by source rocks within the oil and gas system:

[0164] Q C +Q U +Q S ≤Q P

[0165] Where Q C is the conventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ;Q U is the amount of unconventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ;Q S is the shale oil and gas resources (in gas equivalent), unit 10 12 m 3 , Q P is the total generated oil and gas resources (in gas equivalent), unit 10 12 m 3 ;

[0166] 1.2 Natural gas hydrates share the same characteristics as conventional oil and gas resources and conventional heavy oil and asphalt resources in terms of hydrocarbon sources, migration and accumulation dynamics and processes, and reservoir characteristics. Furthermore, natural gas hydrates are confined to stable zones of high pressure and low temperature. Therefore, natural gas hydrates can be considered a special type of conventional oil and gas resource that accumulates in high-pressure, low-temperature reservoirs. Based on this, a correlation model is established for natural gas hydrate resources, conventional oil and gas resources (conventional oil and gas resources refer to those that are generated from organic matter, distributed within a free dynamic field, and migrate by buoyancy, and are not biodegraded) and conventional heavy oil and asphalt resources (conventional heavy oil and asphalt resources refer to those that are generated from organic matter, distributed within a free dynamic field, and migrate by buoyancy, and are biodegraded):

[0167] Q C =Q C1 +Q C2 +Q C3 ≤Q EC

[0168] Where Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;Q EC The hydrocarbon resources (in gas equivalent) discharged by source rocks above the lower limit of buoyancy accumulation and within the free dynamic field, unit 10 12 m 3 ;QC is the conventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ;

[0169] 1.3. Based on the correlation models of natural gas hydrate resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources, a unified model and mass balance equation between natural gas hydrate resources and conventional oil and gas resources is established:

[0170] Q C1 =Q C -Q C2 -Q C3 =f×Q C

[0171] Where Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 10 12 m 3 ;Q EC The hydrocarbon resources (in gas equivalent) discharged by source rocks above the lower limit of buoyancy accumulation and within the free dynamic field, unit 10 12 m 3 ;Q C is the conventional oil and gas resources (in gas equivalent), unit 10 12 m 3 ; f is the proportion of natural gas hydrates in conventional oil and gas resources, unit: %;

[0172] 1.4. Based on the unified model and mass balance equation between natural gas hydrate resources and conventional oil and gas resources, a natural gas hydrate resource determination model is established:

[0173]

[0174] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; Q C1 is the amount of natural gas hydrate resources (in gas equivalent), unit 10 12 m 3 ;Q C2 is the conventional oil and natural gas resources (in gas equivalent), unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources (in gas equivalent), unit 1012 m 3 .

[0175] 2. Obtain the thickness and area of sedimentary rock layers in the global natural gas hydrate stability zone and the natural gas hydrate volume factor, and obtain the thickness and area of sedimentary rock layers and the natural gas volume factor of the global conventional oil and gas resources;

[0176] In this example, 29 sets of global gas hydrate resource assessment results and authoritative data from the global oil and gas industry were selected. Through mathematical and statistical analysis methods, the key parameters required for evaluating the amount of gas hydrate resources based on the analogy of conventional oil and gas resources were obtained, including parameters reflecting the volume of sedimentary rock layers within the gas stability zone, the area of the sedimentary rock layer in the gas hydrate stability zone, and the area of the sedimentary rock layer in the gas hydrate stability zone. GHSZ , thickness H GHSZ and gas hydrate volume factor B gh Data reflecting the volume of sedimentary rock layers of conventional oil and gas reservoirs within the free dynamic field. The area A of the sedimentary rock layers where conventional oil and gas resources are located. conv , thickness H conv and natural gas volume factor B g For details, please see Table 1. Figure 3 、 Figure 4 .

[0177] 3. Obtain the proportion of gaseous hydrocarbons; specifically including:

[0178] 3.1. Obtain the ratio of the amount of gas generated by the global organic matter type III source rock during the biochemical gas generation stage (Ro<0.5%) to the total amount of hydrocarbons generated, which is the first ratio;

[0179] The ratio of gas to total hydrocarbon generated by different organic matter types of source rocks during the biochemical gas generation stage (Ro<0.5%) is as follows: Figure 6 As shown;

[0180] 3.2. The ratio of the gas volume to the total hydrocarbon volume in the world's proven conventional oil and gas reservoirs is obtained as the second ratio;

[0181] The ratio of gas to total hydrocarbons in the world's proven conventional oil and gas reservoirs is as follows: Figure 7 As shown;

[0182] 3.3. The third ratio is obtained by obtaining the weighted average of the ratios of gaseous hydrocarbons to total hydrocarbons generated by source rocks of organic matter types I, II, and III in the global free dynamic field during the biogenic and thermogenic gas generation stages. Specifically:

[0183] obtaining, in a free dynamic field, the ratio of gaseous hydrocarbons generated by type I organic matter source rocks in the biogenic gas generation stage to the total hydrocarbons generated, the ratio of gaseous hydrocarbons generated by type I organic matter source rocks in the thermogenic gas generation stage to the total hydrocarbons generated, the ratio of gaseous hydrocarbons generated by type II organic matter source rocks in the biogenic gas generation stage to the total hydrocarbons generated, the ratio of gaseous hydrocarbons generated by type II organic matter source rocks in the thermogenic gas generation stage to the total hydrocarbons generated, the ratio of gaseous hydrocarbons generated by type III organic matter source rocks in the biogenic gas generation stage to the total hydrocarbons generated, and the ratio of gaseous hydrocarbons generated by type III organic matter source rocks in the thermogenic gas generation stage to the total hydrocarbons generated, respectively, and performing weighted average of the above ratios to obtain a third ratio;

[0184] The ratio of gaseous hydrocarbons to total hydrocarbons generated by source rocks with type I, II, and III kerogen in the free dynamic field during the biogenic gas generation stage and the thermal gas generation stage is shown in the figure below. Figure 8 As shown;

[0185] Step S34: Determine the gaseous hydrocarbon ratio g based on the first ratio, the second ratio, and the third ratio; specifically:

[0186] The third ratio is used as the initial value of the gaseous hydrocarbon ratio, and the initial value of the gaseous hydrocarbon ratio is corrected using the first ratio and the second ratio to obtain the gaseous hydrocarbon ratio g; wherein, when the initial value of the gaseous hydrocarbon ratio is less than or equal to the first ratio and greater than or equal to the second ratio, the gaseous hydrocarbon ratio g is the initial value of the gaseous hydrocarbon ratio; when the initial value of the gaseous hydrocarbon ratio is greater than the first ratio, the gaseous hydrocarbon ratio g is the first ratio; when the initial value of the gaseous hydrocarbon ratio is less than the second ratio, the gaseous hydrocarbon ratio g is the second ratio;

[0187] The global distribution of gaseous hydrocarbons is as follows: Figure 5 shown.

[0188] Table 1

[0189] parameter Minimum Optimal value Maximum <![CDATA[A GHSZ (10 6 km 2 )]]> 5.0 50-30 150 <![CDATA[H GHSZ (m)]]> 10 500-400 1200 <![CDATA[A conv (10 6 km 2 )]]> 162 180 240 <![CDATA[H conv (m)]]> 300 2600-3500 7000 <![CDATA[B gh ]]> 160 164 168 <![CDATA[B g ]]> 35 210 360 g 0.379 0.715-0.67 0.907

[0190] 4. Based on the thickness and area of the sedimentary rock layer in the gas hydrate stability zone and the gas hydrate volume factor, and the thickness and area of the sedimentary rock layer where the conventional oil and gas resources are located and the natural gas volume factor, the following formula is used to determine the proportion of gas hydrate in conventional oil and gas resources:

[0191]

[0192] Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; B gh B is the gas hydrate volume factor, which represents the ratio of the volume of methane hydrate under standard surface conditions to the volume of gas hydrate under reservoir conditions, and the unit is dimensionless; gA is the natural gas volume factor, which represents the ratio of the natural gas volume under standard surface conditions to the natural gas volume under reservoir conditions, and the unit is dimensionless; GHSZ is the area of the sedimentary rock layer in the gas hydrate stability zone, unit 10 6 km 2 ;H GHSZ is the thickness of the sedimentary rock layer in the gas hydrate stability zone, in m; A conv is the area of sedimentary rock layers where conventional oil and gas resources are located, unit 10 6 km 2 ;H conv is the thickness of the sedimentary rock layer where conventional oil and gas resources are located, in m; g is the proportion of gaseous hydrocarbons, in %.

[0193] 5. Obtain conventional oil and natural gas resources and conventional heavy oil and asphalt resources; specifically:

[0194] Based on the evaluation of experts in the field of petroleum geology and exploration and data from authoritative petroleum institutions around the world, the global conventional oil and gas resources are determined to be Q C2 Data and conventional heavy oil and asphalt resources Q C3 data.

[0195] 6. Based on the conventional oil and gas resources, conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in conventional oil and gas resources, the global natural gas hydrate resources are determined using the natural gas hydrate resource determination model.

[0196] In this embodiment, the optimal value of the proportion of natural gas hydrate in conventional oil and gas resources is 0.01-0.03; the global conventional oil resources are 1983.3×10 9 m 3 , global conventional natural gas resources: 672.1×10 12 m 3 The sum of the above two is the global conventional oil and gas resources Q C2 ; Global conventional heavy oil and asphaltene resources Q C3 1438.0×10 12 m 3 The final optimal value of global natural gas hydrate resources is 84×10 12 m 3 , with an average value of 179×10 12 m 3 , final result: 84-179×10 12 m 3 .

[0197] The method for determining the amount of natural gas hydrate resources provided in this embodiment starts from the cutting-edge geological theory, incorporates natural gas hydrate resources into the global oil and gas system, constructs a unified model and mass balance equation, and finds the similarities between natural gas hydrate resources and conventional oil and gas resources in resource types. By analogy with conventional oil and gas resource evaluation methods, a reliable evaluation of global natural gas hydrate resources is conducted. Through this method, the shortcomings of insufficient geological theory and large errors in evaluation methods in the past are solved, and the prediction is based on geological basis and has high credibility; the prediction is based on advanced technology and has high accuracy; the prediction is based on new ideas and has strong innovation. Moreover, this method only uses commonly used evaluation parameters in conventional oil and gas evaluation, and integrates the evaluation results and parameters of hydrates by predecessors. The data type is simple and easy to obtain, and the operation process is simple and fast. In general, after practical application verification, this method has the following advantages: (1) sufficient geological basis and high credibility; (2) distinct technical characteristics and high accuracy; (3) complete and clear ideas and strong innovation; (4) simple and easy to obtain data and strong operability.

[0198] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for determining the amount of natural gas hydrate resources, wherein: The method includes: Obtain the thickness and area of the sedimentary rock layer in the gas hydrate stability zone in the target area and the gas hydrate volume factor; Obtain the thickness and area of the sedimentary rock layers and the natural gas volume factor of the conventional oil and gas resources in the target area; wherein the conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy; Obtaining the proportion of gaseous hydrocarbons in the target area; wherein the proportion of gaseous hydrocarbons refers to the proportion of gaseous hydrocarbons in the discharged hydrocarbons; Determine the proportion of natural gas hydrates in conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layers in the natural gas hydrate stability zone and the natural gas hydrate volume factor, the thickness and area of the sedimentary rock layers in which conventional oil and gas resources are located and the natural gas volume factor, and the proportion of gaseous hydrocarbons in the target area; Obtain the conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area; wherein, conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have not been biodegraded; conventional heavy oil and asphalt resources refer to heavy oil and asphalt resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy, and have been biodegraded; The amount of natural gas hydrate resources in the target area is determined based on the amount of conventional oil and gas resources, conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in conventional oil and gas resources in the target area.

2. The method according to claim 1, wherein Obtaining the proportion of gaseous hydrocarbons in the target area includes: The first ratio is the ratio of the amount of gas generated by the source rock with organic matter type III in the target area during the biochemical gas generation stage to the total amount of hydrocarbons generated; the second ratio is the ratio of the amount of gas to the total amount of hydrocarbons in the proven conventional oil and gas reservoirs in the target area; The third ratio is obtained by obtaining the weighted average of the ratios of gaseous hydrocarbons generated by source rocks of type I, II, and III organic matter in the free dynamic field of the target area during the biogenic gas generation stage and the thermal gas generation stage to the total hydrocarbons generated; Determining the gaseous hydrocarbon ratio of the target area based on the first ratio, the second ratio, and the third ratio; wherein the gaseous hydrocarbon ratio of the target area is less than or equal to the first ratio and greater than or equal to the second ratio; The third ratio is used as the initial value of the gaseous hydrocarbon proportion in the target area, and the first ratio and the second ratio are used to correct the initial value of the gaseous hydrocarbon proportion in the target area to obtain the gaseous hydrocarbon proportion in the target area; wherein, when the initial value of the gaseous hydrocarbon proportion in the target area is less than or equal to the first ratio and greater than or equal to the second ratio, the gaseous hydrocarbon proportion in the target area is the initial value of the gaseous hydrocarbon proportion in the target area; when the initial value of the gaseous hydrocarbon proportion in the target area is greater than the first ratio, the gaseous hydrocarbon proportion in the target area is the first ratio; when the initial value of the gaseous hydrocarbon proportion in the target area is less than the second ratio, the gaseous hydrocarbon proportion in the target area is the second ratio.

3. The method according to claim 1, wherein The proportion of natural gas hydrates in conventional oil and gas resources is determined by the following formula: Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; B gh is the volume factor of natural gas hydrate, unit is dimensionless; B g is the natural gas volume factor, unit is dimensionless; A GHSZ is the area of the sedimentary rock layer in the gas hydrate stability zone, unit 10 6 km 2 ; H GHSZ is the thickness of the sedimentary rock layer in the gas hydrate stability zone, in m; A conv is the area of sedimentary rock layers where conventional oil and gas resources are located, unit 10 6 km 2 ;H conv is the thickness of the sedimentary rock layer where conventional oil and gas resources are located, in m; g is the proportion of gaseous hydrocarbons, in %.

4. The method according to claim 1, wherein Determine the amount of natural gas hydrate resources using a natural gas hydrate resource determination model; wherein the natural gas hydrate resource determination model is a calculation model for natural gas hydrate resources based on the proportion of natural gas hydrates in conventional oil and gas resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources; The model for determining natural gas hydrate resources is: Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; Q C1 is the amount of natural gas hydrate resources, unit 10 12 m 3 ;Q C2 is the conventional oil and gas resources, unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources, unit 10 12 m 3 .

5. A system for determining the amount of natural gas hydrate resources, wherein: The system includes: Gas hydrate parameter acquisition module: used to obtain the thickness and area of the sedimentary rock layer in the gas hydrate stability zone in the target area and the gas hydrate volume factor; Oil and gas resource parameter acquisition module: used to obtain the thickness and area of the sedimentary rock layer where conventional oil and gas resources are located in the target area, as well as the natural gas volume factor; wherein, conventional oil and gas resources refer to oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy; Gaseous hydrocarbon ratio acquisition module: used to obtain the gaseous hydrocarbon ratio of the target area; wherein the gaseous hydrocarbon ratio refers to the ratio of gaseous hydrocarbons in the discharged hydrocarbons; Gas hydrate proportion acquisition module: used to determine the proportion of gas hydrate in conventional oil and gas resources in the target area based on the thickness and area of the sedimentary rock layer in the gas hydrate stability zone and the gas hydrate volume factor, the thickness and area of the sedimentary rock layer where the conventional oil and gas resources are located in the target area and the natural gas volume factor, and the proportion of gaseous hydrocarbons in the target area; Conventional Energy Acquisition Module: used to acquire conventional oil and gas resources and conventional heavy oil and asphalt resources in the target area; conventional oil and gas resources refer to non-biodegraded oil and gas resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy; conventional heavy oil and asphalt resources refer to biodegraded heavy oil and asphalt resources generated by organic matter, distributed within a free dynamic field, and driven by buoyancy; Natural Gas Hydrate Resource Acquisition Module: This module is used to determine the amount of natural gas hydrate resources in a target area based on the amount of conventional oil and gas resources, conventional heavy oil and asphalt resources, and the proportion of natural gas hydrates in conventional oil and gas resources in the target area.

6. The system according to claim 5, wherein: The module for obtaining the proportion of gaseous hydrocarbons includes: The first ratio acquisition submodule is used to obtain the ratio of the amount of gas generated by the source rock with organic matter type III in the target area during the biochemical gas generation stage to the total amount of hydrocarbons generated, which is the first ratio; The second ratio acquisition submodule is used to obtain the ratio of the gas volume to the total hydrocarbon volume in the proven conventional oil and gas reservoirs in the target area, which is the second ratio; The third ratio acquisition submodule is used to obtain the weighted average of the ratios of gaseous hydrocarbons generated by source rocks of organic matter types I, II, and III in the free dynamic field of the target area during the biogenic gas generation stage and the thermal gas generation stage to the total hydrocarbons generated, which is the third ratio; A gaseous hydrocarbon ratio determination submodule is configured to determine the gaseous hydrocarbon ratio of the target area based on the first ratio, the second ratio, and the third ratio; wherein the gaseous hydrocarbon ratio of the target area is less than or equal to the first ratio and greater than or equal to the second ratio; The gaseous hydrocarbon proportion determination submodule is used to use the third ratio as the initial value of the gaseous hydrocarbon proportion of the target area, and use the first ratio and the second ratio to correct the initial value of the gaseous hydrocarbon proportion of the target area to obtain the gaseous hydrocarbon proportion of the target area; wherein, when the initial value of the gaseous hydrocarbon proportion of the target area is less than or equal to the first ratio and greater than or equal to the second ratio, the gaseous hydrocarbon proportion of the target area is the initial value of the gaseous hydrocarbon proportion of the target area; when the initial value of the gaseous hydrocarbon proportion of the target area is greater than the first ratio, the gaseous hydrocarbon proportion of the target area is the first ratio; when the initial value of the gaseous hydrocarbon proportion of the target area is less than the second ratio, the gaseous hydrocarbon proportion of the target area is the second ratio.

7. The system according to claim 5, wherein: The natural gas hydrate ratio acquisition module determines the ratio of natural gas hydrates to conventional oil and gas resources using the following formula: Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; B gh is the volume factor of natural gas hydrate, unit is dimensionless; B g is the natural gas volume factor, unit is dimensionless; A GHSZ is the area of the sedimentary rock layer in the gas hydrate stability zone, unit 10 6 km 2 ; H GHSZ is the thickness of the sedimentary rock layer in the gas hydrate stability zone, in m; A conv is the area of sedimentary rock layers where conventional oil and gas resources are located, unit 10 6 km 2 ;H conv is the thickness of the sedimentary rock layer where conventional oil and gas resources are located, in m; g is the proportion of gaseous hydrocarbons, in %.

8. The system according to claim 5, wherein: The gas hydrate resource acquisition module determines the gas hydrate resource using a gas hydrate resource determination model; wherein the gas hydrate resource determination model is a calculation model for the gas hydrate resource with respect to the proportion of gas hydrate in conventional oil and gas resources, conventional oil and gas resources, and conventional heavy oil and asphalt resources; The model for determining natural gas hydrate resources is: Where, f is the proportion of natural gas hydrate in conventional oil and gas resources, unit: %; Q C1 is the amount of natural gas hydrate resources, unit 10 12 m 3 ;Q C2 is the conventional oil and gas resources, unit 10 12 m 3 ;Q C3 is the conventional heavy oil and asphalt resources, unit 10 12 m 3 .

9. An electronic device comprising a processor, a memory, and a computer program stored in the memory and executable on the processor, wherein when the processor executes the program, the steps of the method for determining the amount of natural gas hydrate resources according to any one of claims 1 to 4 are implemented.

10. A computer-readable storage medium having a computer program stored thereon, wherein when the computer program is executed by a processor, the computer program implements the steps of the method for determining the amount of natural gas hydrate resources according to any one of claims 1 to 4.

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