New district organic matter-rich stratum section natural gas resource quantity estimation method

Abstract

The invention discloses a new district organic matter-rich stratum section natural gas resource quantity estimation method, which comprises the following steps: researching sedimentary environments and later-stage structural evolution of a new district and an adjacent high exploration area, dividing different evaluation units, and determining similarities and differences between the evaluation units and between the evaluation units and the adjacent high exploration area; comparing each evaluation unit with an adjacent high exploration area, and deducing geologic features of a new area; collecting geological data to compile a data table, and compiling a related geological map according to the data table; selecting a proper resource quantity estimation method according to the natural gas occurrence states of different rocks in the target interval of each evaluation unit; the key parameters are valued; and according to the resource quantity estimation method and the parameter values, estimating the natural gas resource quantity of each evaluation unit, and adding the resource quantities of the units to obtain the total natural gas resource quantity of the new region. According to the method, the natural gas resource quantity of the organic matter-rich stratum section of the new district can be quickly and accurately estimated.

Description

Technical Field

[0001] The present invention relates to the technical field of natural gas resource exploration, and more specifically, to a method for estimating the natural gas resource volume in a new area's organic-rich formation section. Background Art

[0002] The organic-rich formation section mainly develops shale, and may also develop glutenite, coal seams, carbonate rocks, or even igneous rocks. Among them, the organic-rich shale and coal seams can both generate and store natural gas, which are respectively called shale gas and coalbed methane, and both belong to unconventional natural gas. The glutenite, carbonate rocks, and igneous rocks in the same formation section can also store the natural gas discharged from the shale and coal seams, that is, conventional natural gas. For these natural gases, there are already mature resource volume calculation methods at home and abroad, and corresponding computer software has even been formed, and they are respectively incorporated into the corresponding standards and specifications. For example, the volumetric method in the "Specification for Estimating Petroleum and Natural Gas Reserves" can be used to estimate the resource volume of tight sandstone gas and tight carbonate rock gas. The "Specification for Estimating Shale Gas Resource Volume and Reserves" proposes the free gas estimation method - volumetric method and adsorbed gas estimation method - volume method, as well as the analogy method for shale gas resource volume. The "Specification for Coalbed Methane Resources / Reserves" proposes the volume method and the analogy method. Generally speaking, when the exploration and development degree is high and various data are very rich, the volumetric method and the volume method are generally used for estimation; when the exploration degree is low and the data are scarce, the genetic method, the analogy method, the empirical method, or the historical trend extrapolation method, the expert subjective evaluation method, etc. are generally used for estimation. The calculation methods include the definite value calculation method, the probability method (i.e., the Monte Carlo method), the fuzzy mathematics method, and the neural network method. Existing research results also show that due to the mainly single exploration and development target / mineral species, the previous natural gas resource volume estimation and evaluation are basically single, and the systematic consideration is insufficient.

[0003] A new area refers to an area where there are no wells drilled for the target layer or only a few parameter wells and pre-exploration wells that have not made major discoveries, and the geophysical exploration workload is very small. At present, when estimating the natural gas resource volume in the organic-rich formation section of a new area, due to the limited accuracy of parameter values in the new area with scarce data, the reliability of the estimation results of directly applying the existing mature resource volume calculation methods for the natural gas resource volume in the new area is also poor, and it cannot meet the needs of providing deployment basis and data support for quickly promoting the exploration and development of the new area. Summary of the Invention

[0004] The object of the present invention is to propose a method for estimating the natural gas resource volume in the organic-rich formation section of a new area. This method is applicable to new areas with scarce data, and can quickly and accurately estimate the natural gas resource volume in the organic-rich formation section of the new area, providing a deployment basis and data support for quickly promoting the exploration and development of the new area.

[0005] To achieve the above object, the present invention proposes a method for estimating the natural gas resource volume in the organic-rich formation section of a new area, including:

[0006] S1: Study the sedimentary environment and late tectonic evolution of the new area and adjacent high-exploration areas, divide the new area into different evaluation units, and clarify the similarities and differences between each evaluation unit and between the new area and adjacent high-exploration areas;

[0007] S2: Thoroughly dissect the geological characteristics of adjacent high-exploration areas, compare each evaluation unit with adjacent high-exploration areas, infer the geological characteristics of the new area, and determine the similarity and comparability between the two;

[0008] S3: Collect relevant geological data of the new area and adjacent high-exploration areas, statistically analyze relevant geological data to compile corresponding data tables, and compile relevant geological maps based on the data tables to provide basic data and intuitive display for subsequent parameter value determination and resource volume estimation;

[0009] S4: According to the gas occurrence states of different rocks in the target interval of each evaluation unit, select appropriate resource volume estimation methods to calculate the resource volumes of unconventional natural gas and conventional natural gas respectively. The unconventional natural gas includes coalbed methane and shale gas, and is divided into adsorbed gas calculation and free gas calculation;

[0010] S5: Comprehensively analyze the changes in various geological characteristics during the organic matter thermal evolution and diagenesis processes, and determine the values of key parameters in the resource volume estimation methods corresponding to each evaluation unit;

[0011] S6: According to the resource volume estimation methods and parameter values corresponding to each evaluation unit, estimate the adsorbed gas, free gas and conventional natural gas resource volumes of unconventional natural gas in each evaluation unit respectively, and add up the resource volumes of each unit to obtain the total natural gas resource volume of the new area.

[0012] Optionally, step S1 specifically includes:

[0013] Expand the research scope from the new area to adjacent high-exploration areas, study the changes in sedimentary environment and its control over the lithological combination of organic-rich mud shale intervals, the influence of tectonic movements, and the lateral variation laws of subsidence-uplift erosion and tectonic deformation in each period, and combine the two to divide the new area into different evaluation units, and clarify the similarities and differences between each evaluation unit and between the new area and adjacent high-exploration areas.

[0014] Optionally, in step S2, thoroughly dissecting the geological characteristics of adjacent high-exploration areas includes:

[0015] Study the lithological / petrographic characteristics, mineral composition, organic matter type and TOC, degree of organic matter evolution, pore structure and physical properties, gas-bearing properties and natural gas occurrence state, natural gas resource abundance and component characteristics, reservoir-forming mechanism and main controlling factors, other reservoir lithologies and mineral compositions, pore structure and physical properties, natural gas sources and migration and accumulation channels, as well as reservoir-forming periods and reservoir-forming mechanisms of coal seams and organic-rich mudstones in adjacent highly explored areas.

[0016] Optionally, in step S2, compare each evaluation unit with the adjacent highly explored area to infer the geological characteristics of the new area, including:

[0017] Carry out a comparison between the evaluation unit and the adjacent highly explored area to infer the lithological / petrographic characteristics and mineral composition, organic matter type and TOC, degree of organic matter evolution, pore structure and physical properties, gas-bearing properties and natural gas occurrence state, natural gas resource abundance and component characteristics, reservoir-forming mechanism and main controlling factors of coal seams and organic-rich mudstones in each evaluation unit.

[0018] Optionally, in step S3, collect relevant geological data of the new area and the adjacent highly explored area, and statistically analyze relevant geological data to compile corresponding data tables, including:

[0019] Collect drilling logging, geophysical, experimental test data, as well as monographs, papers and news report data of the new area and the adjacent highly explored area, and statistically analyze the formation thickness, burial depth, coal seam thickness, coal rank, organic-rich mudstone thickness, TOC of organic-rich mudstone, organic matter type, Ro, other reservoir thicknesses, porosity, natural gas components and isotope data of each well point and outcrop section to compile corresponding data tables.

[0020] Optionally, in step S3, compile relevant geological maps based on the data tables, including:

[0021] Based on the data tables, compile the formation thickness, sedimentary facies map, organic-rich mudstone / coal seam / sandstone / carbonate rock / igneous rock thickness map, burial depth map, comprehensive columnar section map and comparison map of the new area and the adjacent highly explored area;

[0022] When the data is sufficient, also compile the TOC map of organic-rich mudstone, Ro map and porosity maps of each rock.

[0023] Optionally, in step S4, analyze the natural gas occurrence state of different rocks in the target interval of each evaluation unit, including:

[0024] Based on the analysis of the organic matter thermal evolution process of hydrocarbon generation, expulsion and retention and the diagenetic process, dynamically analyze the reservoir characteristics of each lithology at each stage, as well as the natural gas retention / injection volume, preservation conditions and enrichment laws to determine the natural gas occurrence state of different rocks in the target interval of each evaluation unit;

[0025] Among them, the occurrence states of natural gas include adsorbed, free, and dissolved. In the organic-rich mud shale formation section, adsorbed gas and free gas are the main components. In coal seams, adsorbed gas is the main component. Conventional natural gas mainly exists in the free state.

[0026] Optionally, in step S4, the volumetric method is selected to calculate the adsorbed gas resource quantity. The calculation formula of the volumetric method is:

[0027] Q i = 0.01A i H i ρG i (1)

[0028] In the formula: Q i is the adsorbed gas resource quantity of the organic-rich mud shale / coal seam in the i evaluation unit, 10 6 m 3 ;

[0029] A i is the distribution area of the organic-rich mud shale / coal seam in the i evaluation unit;

[0030] H i is the cumulative effective thickness of the organic-rich mud shale / coal seam in the i evaluation unit;

[0031] ρ is the mass of the organic-rich mud shale / coal seam, t / m 3 ;

[0032] G i is the adsorbed gas content of the organic-rich mud shale / coal seam, m 3 / t.

[0033] Optionally, in step S4, the volume method is selected to calculate the free gas resource quantity. The calculation formula of the volume method is:

[0034] Q i = 0.01A i H i Ф i S gi / B gi (2)

[0035] In the formula: Q i is the free gas resource quantity of the organic-rich mud shale / coal seam / other reservoirs in the i unit, 10 8 m 3 ;

[0036] A i is the area of the organic-rich mud shale / coal seam / other reservoirs in the i evaluation unit, km 2 ;

[0037] H iFor the effective thickness of organic-rich shale / coal seam / other reservoirs in the i evaluation unit, m;

[0038] Φ i For the porosity of organic-rich shale / coal seam / other reservoirs in the i evaluation unit, decimal;

[0039] S gi For the original free gas saturation, decimal;

[0040] B gi For the original natural gas formation volume factor, dimensionless.

[0041] Optionally, in step S5, the value taking of the key parameters in the resource quantity estimation method corresponding to each evaluation unit includes:

[0042] Determine the distribution area A of the organic-rich shale / coal seam / other reservoirs in each evaluation unit through the formation thickness map and sedimentary facies map i value;

[0043] Determine the effective thickness H of the organic-rich shale / coal seam / other reservoirs in each evaluation unit through drilling data, formation thickness map or adjacent area comparison data i value;

[0044] Determine the rock mass density ρ, adsorbed gas content G, i porosity Φ i free gas saturation S gi and natural gas formation volume factor B gi value of each evaluation unit by means of experimental measurement, adjacent area comparison or previous experience data.

[0045] The beneficial effects of the present invention are as follows:

[0046] The present invention provides a method for estimating the natural gas resource quantity applicable to the organic-rich formation section in new areas. This method incorporates shale gas, coalbed methane and conventional natural gas into the same system, analyzes their symbiosis and mutual influence, and more accurately evaluates the natural gas resource prospect as a whole. In the case of scarce data in new areas, this method conducts rapid resource quantity estimation through regional analysis and comparison with adjacent known areas, and utilizes the previous regular understanding and related change models. At the same time, by dynamically analyzing the organic matter thermal evolution and diagenetic process and combining with geological characteristics for value taking, the reliability and scientificity of the resource quantity estimation are improved, thereby providing strong technical support for the exploration and development of natural gas resources in new areas.

[0047] The system of the present invention has other features and advantages, which will be apparent from the accompanying drawings incorporated herein and the subsequent detailed description, or will be described in detail in the accompanying drawings incorporated herein and the subsequent detailed description, and these accompanying drawings and detailed description are jointly used to explain the specific principles of the present invention. Description of the Drawings

[0048] By describing the exemplary embodiments of the present invention in more detail in conjunction with the accompanying drawings, the above and other objects, features, and advantages of the present invention will become more apparent. In the exemplary embodiments of the present invention, the same reference numerals generally represent the same components.

[0049] Figure 1 It is a flowchart of a method for estimating the natural gas resource volume in a new area rich in organic texture formation section according to an embodiment of the present invention.

[0050] Figure 2 It is a graph showing the relationship between coalbed gas content, coal rank, and burial depth in an embodiment of the present invention (according to Long Shengxiang, 1998).

[0051] Figures 3a - 3d They are respectively the gas production rate curve of type II2 siliceous shale, the gas production rate curve of type II2 clay shale, the gas production rate curve of type II2 calcareous shale, and the gas production rate curve of type III organic-rich mud shale in an embodiment of the present invention.

[0052] Figure 4 It is a graph showing the diagenetic evolution sequence of sandstone and the change of porosity in an embodiment of the present invention (Shi Zhensheng et al., 2018).

[0053] Figure 5 It is a graph showing the change of shale porosity with Ro in the Longtan Formation in northeastern Sichuan in an embodiment of the present invention (Li Jin et al., 2022). Detailed Description of the Embodiments

[0054] In natural gas resource exploration, new areas usually refer to those areas with low exploration levels and limited data. The organic-rich mud shale formation section refers to the formation section mainly composed of mud shale with TOC≥1.0% (accounting for ≥50%), in which there may be coal seams and interlayers of sandy conglomerate, carbonate rock, and even igneous rock, forming different rock interbeds with equal or unequal thickness. Types and occurrence modes of natural gas resources in the organic-rich mud shale formation section: ① Shale gas occurs in three ways: adsorption, free, and dissolved, with very little dissolved; ② Coalbed gas is mainly adsorbed, with some free or dissolved; ③ Conventional natural gas almost entirely occurs in a free state.

[0055] In the formation section of organic-rich mudstone shale, the organic-rich mudstone shale has a TOC ≥ 1.0%, and both it and coal seams are good to high-quality hydrocarbon source rocks. Under the high temperature and high pressure conditions formed by long-term deep burial, a large amount of natural gas has been generated, expelled, and retained. These organic-rich mudstone shales and coal seams have also gradually developed organic matter pores, intergranular / intragranular pores of minerals, microfractures, bedding / joints during the thermal evolution - diagenesis process, forming reservoirs with certain physical properties and dynamically retaining and enriching natural gas to form reservoirs. In addition, sandstones, conglomerates, siltstones, carbonate rocks, and igneous rocks existing within this formation section have gradually evolved into conventional or tight reservoirs during the diagenesis process and accumulated some of the natural gas expelled from the mudstone shales and coal seams to form reservoirs. The roof and floor of the organic-rich mudstone shale formation section are often dense rock layers with good continuity, which are good capping / sealing layers for the natural gas in this formation section.

[0056] It can be inferred from the above that the organic-rich mudstone shale formation section is actually a relatively independent and complete petroleum system. During the long-term geological tectonic evolution process, under the action of a unified temperature - pressure field, different reactions occur in different rocks and different components within it, but they are interconnected and interact with each other. When reaching the high - overmature stage, i.e., the late diagenetic stage, a large amount of natural gas is generated. Some is retained in the mudstone shale to form shale gas, and some is retained in the coal seam to form coalbed methane. Some is expelled and short-distance migrated to sandstones, conglomerates, siltstones, carbonate rocks, and volcanic rocks to form conventional gas respectively.

[0057] Since new areas often lack detailed geological data, traditional resource estimation methods such as the volumetric method and the volume method are difficult to apply directly because they rely on a large number of geological parameters. In addition, the organic-rich formation section in new areas has complex geological characteristics and diverse occurrence states of natural gas, further increasing the difficulty of resource estimation. In the existing technologies, although there are already various resource estimation methods, the following problems exist in their application in new areas:

[0058] 1. Difficulty in parameter value determination: Due to the lack of data in new areas, it is difficult to accurately obtain key parameters such as porosity and adsorbed gas content.

[0059] 2. Lack of systematicness: Existing methods mostly target single resource types and lack systematic analysis of multiple resources within the organic-rich formation section.

[0060] 3. Low estimation accuracy: In the case of limited data, the estimation results of traditional methods are less reliable and difficult to meet the exploration and development needs of new areas.

[0061] Since the natural gas source-reservoir-caprock assemblage in the organic-rich formation section is good and it is a complete petroleum system, and shale gas, coalbed methane, sandstone gas, carbonate gas, and igneous rock gas are interconnected and interact with each other. Therefore, for new areas with particularly scarce data, under the concept of the system, the interconnections and interactions among various resources in the organic-rich formation section should be analyzed, relevant parameters should be determined uniformly, and mutual speculation should be carried out based on their respective geological characteristics. Then, reasonable values of relevant parameters should be taken and comparative analysis should be conducted, and finally, rapid estimation of resource volume should be carried out to estimate and evaluate the reliability.

[0062] Therefore, the present invention provides a method for estimating the natural gas resource volume in the organic-rich formation section of new areas. Based on the data of the evaluation area and by analogy with adjacent highly explored areas, under the guidance of the research results of the regional sedimentary environment, try to compile maps of burial depth, stratigraphic correlation, series, and plane distribution maps of various types of rocks, and analyze the TOC, organic matter type, Ro, coal rank, pore characteristics, physical properties, gas content, gas composition, structural characteristics, and preservation conditions of different lithologies or sub-layers within the formation section; based on the analysis of the processes of organic matter thermal evolution, hydrocarbon generation, expulsion, and retention and diagenesis, dynamically analyze the reservoir characteristics of each lithology at each period, as well as the natural gas retention / injection volume, preservation conditions, and enrichment laws, select a suitable estimation method, and accurately determine the values of each parameter by comprehensively considering various geological characteristics during the processes such as organic matter thermal evolution and diagenesis. Finally, estimate the resource volume. By systematically analyzing geological characteristics and dynamically analyzing the occurrence state of natural gas, the accuracy and reliability of resource volume estimation are improved.

[0063] The present invention will be described in more detail below with reference to the accompanying drawings. Although the preferred embodiments of the present invention are shown in the drawings, it should be understood that the present invention can be implemented in various forms and should not be limited by the embodiments described herein. On the contrary, these embodiments are provided to make the present invention more thorough and complete, and to fully convey the scope of the present invention to those skilled in the art.

[0064] Example 1

[0065] As Figure 1 shown, this embodiment provides a method for estimating the natural gas resource volume in the organic-rich formation section of new areas, including:

[0066] S1: Study the sedimentary environment and late tectonic evolution of the new area and adjacent highly explored areas, divide the new area into different evaluation units, and clarify the similarities and differences among the evaluation units and between the evaluation units and adjacent highly explored areas;

[0067] Specifically, in this step, starting from a larger area, the research scope is expanded from the new area to the adjacent high-exploration area. The changes in sedimentary environment and its control over the lithologic assemblage of the organic-rich mud shale formation section, the influence of tectonic movements, and the lateral variation laws of subsidence- uplift erosion and tectonic deformation in each period are studied. By combining the two, different evaluation units are divided in the new area, and the similarities and differences between each evaluation unit and the adjacent high-exploration area are clarified.

[0068] S2: Conduct a detailed dissection of the geological characteristics of the adjacent high-exploration area, compare each evaluation unit with the adjacent high-exploration area, infer the geological characteristics of the new area, and determine the similarity and comparability between the two.

[0069] This step specifically includes:

[0070] First, conduct a detailed dissection of the adjacent high-exploration area, study the lithology / petrography characteristics and mineral composition of coal seams and organic-rich mud shales, organic matter types and TOC, degree of organic matter evolution, pore structure and physical properties, gas-bearing properties and natural gas occurrence states, natural gas resource abundance and component characteristics, hydrocarbon accumulation mechanisms and main controlling factors, etc. Study the lithology and mineral composition of other reservoirs, pore structure and physical properties, sources of natural gas and migration and accumulation channels, hydrocarbon accumulation periods and accumulation mechanisms, etc.

[0071] Second, carry out a comparison between the evaluation unit and the adjacent high-exploration area, infer the lithology / petrography characteristics and mineral composition of coal seams and organic-rich mud shales, organic matter types and TOC, degree of organic matter evolution, pore structure and physical properties, gas-bearing properties and natural gas occurrence states, natural gas resource abundance and component characteristics, hydrocarbon accumulation mechanisms and main controlling factors, etc. within each evaluation unit. At the same time, determine the similarity and comparability between the two.

[0072] S3: Collect relevant geological data of the new area and the adjacent high-exploration area, statistically analyze relevant geological data to compile corresponding data tables, and compile relevant geological maps based on the data tables to provide basic data and intuitive displays for subsequent parameter value determination and resource volume estimation.

[0073] This step specifically includes:

[0074] First, widely collect data such as drilling logging, geophysics, experimental testing data, monographs, papers, news reports, etc. of the new area and its adjacent areas, statistically analyze data such as formation thickness, burial depth, coal seam thickness, coal rank (degree of metamorphism), organic-rich mud shale thickness, TOC of organic-rich mud shale, organic matter type, Ro, thickness of other reservoirs, porosity, natural gas components, isotopes, etc. of each well point and outcrop section, and compile corresponding data tables.

[0075] Secondly, based on the data table, prepare planar maps such as formation thickness maps, sedimentary facies maps, thickness maps of organic-rich mudstone / shale / coal seams / sandstones / carbonate rocks / igneous rocks, burial depth maps, etc., as well as comprehensive columnar sections and correlation diagrams. When there is a large amount of data in the new area, maps such as TOC maps, Ro maps, and porosity maps of various rocks of organic-rich mudstone / shale can also be prepared.

[0076] S4: According to the gas occurrence states of different rocks in the target interval of each evaluation unit, select appropriate resource estimation methods to calculate the resources of unconventional natural gas and conventional natural gas respectively. The unconventional natural gas includes coalbed methane and shale gas, and is divided into adsorbed gas calculation and free gas calculation;

[0077] Among them, analyzing the gas occurrence states of different rocks in the target interval of each evaluation unit includes:

[0078] Based on the analysis of the process of hydrocarbon generation, expulsion, and retention during organic matter thermal evolution and the diagenetic process, dynamically analyze the reservoir characteristics of each lithology in each period, as well as the amount of gas retention / injection, preservation conditions, and enrichment laws, so as to determine the gas occurrence states of different rocks in the target interval of each evaluation unit; the gas occurrence states include adsorption, free, and dissolved. In the organic-rich mudstone / shale formation interval, adsorbed gas and free gas are the main components. In coal seams, adsorbed gas is the main component, and conventional natural gas is mainly stored in a free state.

[0079] Specifically, the gas occurrence states of different rocks in the organic-rich mudstone / shale formation interval are different, so different methods need to be adopted for resource estimation:

[0080] (1) For adsorbed gas, the volume method is mainly used for estimation, and the formula is as follows:

[0081] Q i =0.01A i H i ρG i (1)

[0082] In the formula: Q i is the adsorbed gas resource of organic-rich mudstone / shale / coal seam in unit i, 10 6 m 3 ;

[0083] A i is the distribution area of organic-rich mudstone / shale / coal seam in unit i, generally obtained from the map, km 2 ;

[0084] H i is the cumulative effective thickness of organic-rich mudstone / shale / coal seam in unit i, obtained by arithmetic mean of the thickness of data points or by area weighing of the thickness map, m;

[0085] ρ is the mass of organic-rich mudstone / shale / coal seam, t / m 3;

[0086] G i is the adsorbed gas content of organic-rich mud shale / coal seam, which can be split from the total gas content, m 3 / t.

[0087] (2) For free gas, the volumetric method is mainly used for estimation, and the formula is as follows:

[0088] Q i = 0.01A i H i Ф i S gi / B gi (2)

[0089] In the formula: Q i is the free gas resource volume of organic-rich mud shale / coal seam / other reservoirs in unit i, 10 8 m 3 ;

[0090] A i is the area of organic-rich mud shale / coal seam / other reservoirs in unit i, generally obtained directly from the map, km 2 ;

[0091] H i is the effective thickness of organic-rich mud shale / coal seam / other reservoirs in unit i, taking the arithmetic average of the thickness of data points, or taking the area-weighted value of the thickness map, m;

[0092] Φ i is the porosity of organic-rich mud shale / coal seam / other reservoirs in unit i, taking experimental values, or taking values by comparing with adjacent areas, decimal;

[0093] S gi is the original free gas saturation, taking experimental values, or taking values by well logging interpretation, or taking values by comparing with adjacent areas, decimal;

[0094] B gi is the original gas formation volume factor, calculated from experimental data and temperature and pressure, or taking values by comparing with adjacent areas, dimensionless.

[0095] If the parameters such as gas content in different coal seams and organic-rich mud shales in the target interval vary greatly, or the structural characteristics, burial depth, and preservation conditions vary greatly in the plane, resulting in large differences in parameters such as gas content in coal seams and organic-rich mud shales, multiple vertical or horizontal units can be divided, and the resource volumes are estimated separately and then accumulated.

[0096] Coalbed methane is basically adsorbed gas, so only the volumetric method is used to estimate the resource volume; shale gas mainly consists of adsorbed gas and free gas, and the volume method and volumetric method are needed to estimate the resource volume respectively; conventional gas is basically free gas, so only the volumetric method is used to estimate the resource volume.

[0097] Optionally, when there is less data in the new area and relevant parameter values cannot be obtained, the analogy method (volume density analogy method, area abundance analogy method) can also be used to estimate the resource volume.

[0098] S5: Comprehensively analyze the variation laws of various geological characteristics during the organic matter thermal evolution and diagenesis processes, and determine the values of the key parameters in the resource volume estimation methods corresponding to each evaluation unit;

[0099] In this step, determining the values of the key parameters in the resource volume estimation methods corresponding to each evaluation unit includes:

[0100] Determine the distribution area A of the organic matter-rich shale / coal seam / other reservoirs in each evaluation unit through the stratigraphic thickness map and sedimentary facies map i value;

[0101] Determine the effective thickness H of the organic matter-rich shale / coal seam / other reservoirs in each evaluation unit through drilling data, stratigraphic thickness map or comparison data of adjacent areas i value;

[0102] Determine the rock mass density ρ, adsorbed gas content G i , porosity Φ i , free gas saturation S gi and the natural gas volume coefficient B gi value.

[0103] Specifically, the process of determining parameter values in this embodiment is as follows:

[0104] (1) Uniformly determine the degree of evolution

[0105] First, through the coal rank and Ro comparison table (according to Chen Hongbo, 2019), the coal rank can be determined based on Ro, or Ro can be determined based on the coal rank, that is, the organic matter thermal evolution degrees of the coal seam and organic matter-rich shale can be determined simultaneously, and then the hydrocarbon generation stage can be determined.

[0106]

[0107] Second, determine the diagenesis stage of the rock according to Ro.

[0108]

[0109] (2) Determine the hydrocarbon generation amounts of the coal seam and different types of organic matter

[0110] First, based on Figure 2 , the gas content of the coal seam is determined by combining the coal rank and burial depth. The relationship between the gas content of the coal seam, coal rank and burial depth can also be re-established by researchers according to the specific data of the study area and adjacent areas.

[0111] Second, based on Figures 3a - 3d , the gas generation amount of organic matter-rich mud shale with different mineral compositions and different types of organic matter is determined, which is used as the upper limit value of shale gas resources in the study area. Regarding the gas production rate curves of different mud shales, researchers can also re-establish them according to the specific data of the study area and adjacent areas.

[0112] (3) Estimation of adsorbed gas resources in organic matter-rich mud shale / coal seams

[0113] Quality of coal seams and organic matter-rich mud shale: First, take values based on experimental data; second, take values by comparing data from adjacent areas; third, take values according to the theoretical / empirical values established by predecessors. For argillaceous rocks, it is 2.0 - 2.5 tons per cubic meter, and appropriate values can be taken according to changes in mineral composition and porosity. For lignite, it is 1.28 - 1.42 tons per cubic meter, for bituminous coal, it is 1.27 - 1.33 tons per cubic meter, and for anthracite, it is 1.40 - 1.80 tons per cubic meter.

[0114] Adsorbed gas content in coal seams and organic matter-rich mud shale: First, take experimental values; second, take values by comparing data from adjacent areas; third, take empirical values based on the statistical data of predecessors. For example, for lignite, it is < 6 m 3 / t, for gas coal, it is < 11 m 3 / t, for fat coal, it is < 15 m 3 / t, for coking coal, lean coal, and lean bituminous coal, it is 18 - 20 m 3 / t, and for anthracite, it is above 25 m 3 / t.

[0115] Use formula (1) to calculate the adsorbed gas resources of each unit, and then sum up all the units of coal seams and organic matter-rich mud shale units to obtain the adsorbed gas resources of the whole region.

[0116] (4) Estimation of free gas resources in organic matter-rich mud shale / coal seams

[0117] Porosity: First, take values based on experimental data; second, take values by comparing data from adjacent areas; third, take values according to the theoretical / empirical values established by predecessors. For example, for tight sandstone, take values Figure 4 by interpolation according to the diagenetic stage or Ro; for organic matter-rich mud shale, take values Figure 5 by interpolation according to diagenesis and Ro.

[0118] Original gas saturation: First, take values based on experimental data or logging interpretation results; second, take values by comparing data from adjacent areas; third, take values according to the theoretical / empirical values established by predecessors. For example, for tight sandstone, generally take < 60%; for organic matter-rich mud shale, take 50 - 70% under high-pressure - ultra-high-pressure conditions and about 40% under normal pressure conditions with poor preservation conditions.

[0119] Original gas formation volume factor, either calculated from experimental data and temperature, pressure, or taken by comparing with adjacent areas, dimensionless.

[0120] Calculate the free gas resources of organic-rich mud shale / coal seams for each unit using formula (2). Similarly, the conventional natural gas resources can also be calculated using formula (2).

[0121] S6: According to the resource estimation methods and parameter values corresponding to each evaluation unit, estimate the adsorbed gas, free gas, and conventional natural gas resources of each evaluation unit respectively, and add up the resources of each unit to obtain the total natural gas resources of the new area.

[0122] Specifically, add up the adsorbed gas resources and free gas resources of organic-rich mud shale / coal seams in each unit, and then add the conventional natural gas resources of other reservoirs in each unit to obtain the total natural gas resources of the study area.

[0123] In the field of shale gas exploration and development in China, it has gradually expanded from the Silurian marine strata in the Sichuan Basin to multi-strata across the country. In addition to shale gas, the organic-rich mud shale sections may also be enriched in coalbed methane and conventional natural gas. The main idea of this method is to incorporate shale gas, coalbed methane, and conventional natural gas into the same system, analyze their symbiosis, coexistence, interconnection, and mutual influence during the evolution process, and can accurately evaluate the natural gas resource prospects as a whole.

[0124] In summary, this embodiment provides a method for quickly and simply estimating natural gas resources in a newly explored area. In the case of very few data and low understanding in a newly explored area, fully carry out larger area analysis and in-depth comparison with adjacent known areas, and use the regular understanding of predecessors, relevant change models, and empirical values to perform simple, clear, and rapid resource estimation, providing a deployment basis and data support for quickly promoting the exploration and development of the new area.

[0125] Example 2

[0126] When analyzing the shale gas resource prospects in the Permian in the Fuling area, considering that there are only logging data of a few wells in the Fuling area, based on the method of the present invention, the research scope is expanded to Chongqing City and even the entire Sichuan Basin, and nearly 200 well data and papers are collected. On the one hand, data is sorted out to compile plane maps, columnar maps, and comparison maps of formation thickness, sedimentary facies, mudstone thickness, organic-rich mud shale thickness, coal seam thickness, burial depth, TOC, etc., to determine the spatial variation of various geological characteristics, and then infer the geological characteristics of the Fuling area; on the other hand, based on the previous tectonic movement analysis, the study of the subsidence- uplift and erosion history and the temperature-pressure history of the target layer of typical wells is carried out, and then the hydrocarbon generation, expulsion, and retention history of organic matter and the diagenetic process, as well as the lithology, pore type, physical properties, gas-bearing property, and compressibility of mud shale / coal seams controlled by the two, are analyzed, and the reservoir formation mode and enrichment law are summarized. Based on the above two aspects of research, the estimation of coalbed methane and shale gas resources is carried out, and the results show that a resource base with a proven reserve of 500-800 billion cubic meters and a production capacity of about 5 billion cubic meters can be formed.

Claims

1. A method for estimating the natural gas resource volume in a new area's rich organic stratum section, characterized in that, Including: S1: Study the sedimentary environment and late-stage tectonic evolution of the new area and adjacent high-exploration areas, divide the new area into different evaluation units, and clarify the similarities and differences between each evaluation unit and between the new area and adjacent high-exploration areas; S2: Thoroughly analyze the geological characteristics of adjacent high-exploration areas, compare each evaluation unit with adjacent high-exploration areas, infer the geological characteristics of the new area, and determine the similarity and comparability between the two; S3: Collect relevant geological data of the new area and adjacent high-exploration areas, statistically analyze relevant geological data to compile corresponding data tables, and compile relevant geological maps based on the data tables to provide basic data and intuitive displays for subsequent parameter extraction and resource volume estimation; S4: According to the natural gas occurrence states of different rocks in the target intervals of each evaluation unit, select appropriate resource volume estimation methods to calculate the resources of unconventional natural gas and conventional natural gas respectively. The unconventional natural gas includes coalbed methane and shale gas, and is divided into adsorbed gas calculation and free gas calculation; S5: Comprehensively analyze the variation laws of various geological characteristics during the organic matter thermal evolution and diagenesis processes, and extract key parameters in the resource volume estimation methods corresponding to each evaluation unit; S6: According to the resource volume estimation methods and parameter extractions corresponding to each evaluation unit, estimate the adsorbed gas, free gas in unconventional natural gas and conventional natural gas resources of each evaluation unit respectively, and add up the resource volumes of each unit to obtain the total natural gas resources of the new area.

2. The natural gas resource volume estimation method for the new area rich in organic texture strata segments according to claim 1, wherein Step S1 specifically includes: Expand the research scope from the new area to adjacent high-exploration areas, study the sedimentary environment changes and their control over the lithological assemblage of the organic-rich mud shale interval, the influence of tectonic movements, and the lateral variation laws of subsidence- uplift denudation and tectonic deformation in each period, and combine the two to divide the new area into different evaluation units, and clarify the similarities and differences between each evaluation unit and between the new area and adjacent high-exploration areas.

3. The natural gas resource quantity estimation method for the new area rich in organic texture formation section according to claim 1, characterized in that, In step S2, the thorough analysis of the geological characteristics of adjacent high-exploration areas includes: Study the lithological / petrographic characteristics and mineral compositions, organic matter types and TOC, organic matter evolution degree, pore structures and physical properties, gas-bearing properties and natural gas occurrence states, natural gas resource abundances and component characteristics, hydrocarbon accumulation mechanisms and main controlling factors, other reservoir lithological and mineral compositions, pore structures and physical properties, natural gas sources and migration and accumulation channels, and hydrocarbon accumulation periods and mechanisms of coal seams and organic-rich mud shales in adjacent high-exploration areas.

4. The method for estimating the natural gas resource volume in the new area rich in organic texture formation section according to claim 3, characterized in that, In step S2, when comparing each evaluation unit with adjacent high-exploration areas, inferring the geological characteristics of the new area includes: Carry out the comparison between the evaluation unit and adjacent high-exploration areas, and infer the lithological / petrographic characteristics and mineral compositions, organic matter types and TOC, organic matter evolution degree, pore structures and physical properties, gas-bearing properties and natural gas occurrence states, natural gas resource abundances and component characteristics, hydrocarbon accumulation mechanisms and main controlling factors of coal seams and organic-rich mud shales in each evaluation unit.

5. The method for estimating the natural gas resource volume in the new area rich in organic strata according to claim 1, wherein In step S3, collect relevant geological data of the new area and adjacent high-exploration areas, statistically analyze relevant geological data to compile corresponding data tables, including: Collect the drilling logging, geophysical, experimental test data, monographs, papers and news reports in the new area and adjacent high exploration areas, and count the formation thickness, burial depth, coal seam thickness, coal rank, thickness of organic-rich mud shale, TOC of organic-rich mud shale, organic matter type, Ro, thickness of other reservoirs, porosity, natural gas components and isotope data at each well point and outcrop section, and compile the corresponding data tables.

6. The method for estimating the natural gas resource volume in the new area rich in organic texture formation section according to claim 5, characterized in that, In step S3, compile relevant geological maps according to the data tables, including: Compile the formation thickness, sedimentary facies map, thickness maps of organic-rich mud shale / coal seam / sandstone / carbonate rock / igneous rock, burial depth map, comprehensive columnar section map and correlation map of the new area and adjacent high exploration areas according to the data tables; When there is sufficient data, also compile the TOC map of organic-rich mud shale, Ro map and porosity maps of each rock.

7. The method for estimating the natural gas resource volume in the new area rich in organic strata according to claim 1, characterized in that, In step S4, analyze the occurrence states of natural gas in different rocks in the target interval of each evaluation unit, including: Based on the analysis of the hydrocarbon generation, expulsion and retention process during organic matter thermal evolution and the diagenetic process, dynamically analyze the reservoir characteristics of each lithology at different times, as well as the natural gas retention / injection volume, preservation conditions and enrichment laws, so as to determine the occurrence states of natural gas in different rocks in the target interval of each evaluation unit; Among them, the occurrence states of natural gas include adsorption, free and dissolved. In the organic-rich mud shale formation section, it is mainly adsorbed gas and free gas. In the coal seam, it is mainly adsorbed gas. Conventional natural gas mainly occurs in the free state.

8. The method for estimating the natural gas resource volume in the new area's rich organic texture formation section according to claim 7, characterized in that, In step S4, select the volume method to calculate the adsorbed gas resource volume. The calculation formula of the volume method is: Q i = 0.01 A i H i ρG i (1) Where: Q i is the adsorbed gas resource amount of organic-rich mud shale / coal seam in the i evaluation unit, 10 6 m 3 ; A i is the distribution area of organic-rich mud shale / coal seam in the i evaluation unit; H i For evaluating the cumulative effective thickness of organic-rich mud shale / coal seam in the i evaluation unit; ρ is the mass of organic-rich shale / coal seam, t / m 3 ; G i Adsorbed gas content of organic-rich mud shale / coal seam, m 3 / t.

9. The method for estimating the natural gas resource volume in the new area rich in organic texture formation section according to claim 8, characterized in that, In step S4, select the volumetric method to calculate the free gas resource volume. The calculation formula of the volumetric method is: Q i = 0.01 A i H i Ф i S gi / B gi (2) Where: Q i is the free gas resource volume of organic-rich mud shale / coal seam / other reservoirs in the i-th unit, 10 8 m 3 ; A i is the area of organic-rich mud shale / coal seam / other reservoirs in the i evaluation unit, km 2 ; H i is the effective thickness of organic-rich mud shale / coal seam / other reservoirs in the i evaluation unit, m; Φ i Porosity of organic-rich mud shale / coal seam / other reservoir in evaluation unit i, decimal S gi is the original free gas saturation, in decimals; B gi is the original natural gas volume coefficient, dimensionless.

10. The method for estimating the natural gas resource volume in the new area rich in organic texture formation section according to claim 9, characterized in that, In step S5, determine the values of the key parameters in the resource volume estimation methods corresponding to each evaluation unit, including: Determine the distribution area A of organic-rich shale / coal seam / other reservoirs in each evaluation unit through the formation thickness map and sedimentary facies map i value; Determine the value of the effective thickness H of the organic-rich shale / coal seam / other reservoir in each evaluation unit through drilling data, formation thickness maps or comparison data from adjacent areas i ; Determine the rock mass density ρ, adsorbed gas content G, i , porosity Φ i , free gas saturation S gi and natural gas volume coefficient B gi values of each evaluation unit through experimental measurement, comparison with adjacent areas, or taking values from previous experience data.

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