Method and device for obtaining shale gas content while drilling, electronic equipment and storage medium

Abstract

This invention relates to the field of shale gas content monitoring technology while drilling, and provides a method, apparatus, electronic equipment, and storage medium for obtaining shale gas content while drilling. The method includes: establishing a reservoir type classification standard based on porosity and total gas content; determining the total gas content range corresponding to each category of the reservoir type classification standard according to the standard; establishing a scatter plot of the organic carbon content versus total gas content; and obtaining the organic carbon content corresponding to each category of the reservoir type classification standard based on the total gas content range, thereby establishing a shale reservoir type classification standard based on organic carbon content. This invention enables the determination of total gas content in shale gas while drilling. Compared to traditional, precise but costly methods using closed core sampling laboratories to analyze gas content, this method eliminates the need to send core samples to a laboratory, significantly reducing costs and enabling large-scale on-site evaluation during drilling.

Description

Technical Field

[0001] This invention relates to the field of monitoring the gas content of shale gas while drilling, and is a method, device, electronic equipment and storage medium for obtaining the gas content of shale gas while drilling. Background Technology

[0002] In shale gas exploration and development, shale gas content refers to the total amount of natural gas contained in each ton of rock, converted to standard conditions (pressure 101.325 kPa, temperature 25℃). This includes free gas, adsorbed gas, and trace dissolved gas, primarily adsorbed and free gas. The amount of free gas depends mainly on reservoir porosity, water saturation, and the number of natural fractures. Adsorbed gas is generally evaluated using isothermal adsorption curves to assess its maximum adsorption capacity. A more accurate method for determining gas content involves closed-loop core sampling, followed by rapid laboratory analysis. However, this method is costly, unsuitable for large-scale on-site evaluation of shale gas content, and slow, limiting its application in real-time assessment of development wells.

[0003] Patent application CN109063296A discloses a method for calculating shale gas content while drilling. The method includes: establishing calculation models for lost gas, desorbed gas, and residual gas components in shale gas content based on correlation analysis of regional core gas content components with uranium content in cuttings gamma ray spectroscopy and total hydrocarbon content from gas logging; integrating these calculation models to form a shale gas content calculation model; and performing while-drilling calculations of shale gas content based on this model. This method uses three components of shale gas content from core analysis as the basis for establishing the gas content interpretation model, providing a more objective approach than other data (well logging interpretation of adsorbed gas and free gas), thus addressing the shortcomings of existing methods for calculating shale gas content while drilling.

[0004] Patent application CN108107182A discloses a method for determining the content of free gas and adsorbed gas in shale gas. This method involves collecting gas samples from different temperature ranges during shale gas drilling operations, combining the total gas content from the field analysis with methane carbon isotope experimental data to determine the content of free gas and adsorbed gas in the shale gas. This method can quickly obtain the content of free gas and adsorbed gas in shale formations and directly correlate it with the shale gas content, reducing the influence of intermediate parameters and improving the accuracy of the results. It also has the advantages of being easy to promote and implement. Summary of the Invention

[0005] This invention provides a method, apparatus, electronic device, and storage medium for obtaining shale gas content during drilling, which overcomes the shortcomings of the prior art and effectively solves the problem that existing core gas content analysis methods are not suitable for on-site evaluation of shale gas content.

[0006] One of the technical solutions of this invention is achieved through the following measures: a method for obtaining gas content in shale gas during drilling, comprising:

[0007] Porosity and organic carbon content were obtained from shale samples of several known reservoir types;

[0008] Based on the porosity and organic carbon content of shale samples of several known reservoir types, the corresponding total gas content is calculated;

[0009] Scatter plots of porosity and total gas content were drawn for shale samples of several known reservoir types, and a reservoir type classification standard based on porosity and total gas content was established.

[0010] Based on the reservoir type classification standard based on porosity and gas content, the total gas content range corresponding to each category of the reservoir type classification standard is obtained.

[0011] A scatter plot of organic carbon content versus total gas content is established. Based on the total gas content range corresponding to each category of the reservoir type classification standard, the organic carbon content corresponding to each category of the reservoir type classification standard is obtained, thereby establishing a shale reservoir type classification standard based on organic carbon content.

[0012] For shale samples belonging to the same block with unknown reservoir types, obtain the organic carbon content of the shale samples with unknown reservoir types, and identify the reservoir type of the shale samples with unknown reservoir types by comparing them with the shale reservoir type classification standard based on organic carbon content.

[0013] The reservoir type can generally be determined through well logging interpretation.

[0014] The following are further optimizations and / or improvements to one of the above-mentioned inventive technical solutions:

[0015] For the Jimsar block shale or the Santanghu block shale, the total gas content is calculated using the following formula:

[0016] When K = 0.0115P - 0.0153, Q = 33.572 (T2 / T1). -0.583 ;

[0017] When K = 0.0013P 2.975 At that time, Q = 0.6228TOC - 0.2952;

[0018] When K=0.0089e 0.6922P At that time, Q = 1.3803TOC - 4.0148;

[0019] In the formula: K is the permeability of the shale sample, mD; P is the porosity of the shale sample, %; Q is the total gas content of the shale gas sample at the same well depth as the shale sample, m. 3 / t; TOC is the organic carbon content of the shale sample, %; T2 is the maximum total hydrocarbon value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %; T1 is the total hydrocarbon base value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %.

[0020] The scatter plot of porosity versus total gas content for the shale samples of the aforementioned known reservoir types is plotted with porosity on the x-axis and total gas content on the y-axis.

[0021] The scatter plot of organic carbon content versus total gas content described above uses the total gas content as the horizontal axis and the organic carbon content as the vertical axis.

[0022] The second technical solution of the present invention is achieved through the following measures: an apparatus for applying the method for obtaining gas content in shale gas during drilling as described in one of the technical solutions, comprising:

[0023] Porosity and Organic Carbon Content Acquisition Module: Acquires the porosity and organic carbon content of shale samples from several known reservoir types;

[0024] Total gas content acquisition module: Calculates the corresponding total gas content based on the porosity and organic carbon content of shale samples of several known reservoir types;

[0025] First classification standard module: Draw scatter plots of porosity and total gas content of shale samples of several known reservoir types, and establish a reservoir type classification standard based on porosity and total gas content;

[0026] Total gas content range acquisition module: Based on the reservoir type classification standard based on porosity and gas content, the total gas content range corresponding to each category of the reservoir type classification standard is obtained;

[0027] The second classification standard module: establishes a scatter plot of the organic carbon content and total gas content, obtains the organic carbon content corresponding to each category of the reservoir type classification standard according to the total gas content range of each category, and thus establishes a shale reservoir type classification standard based on organic carbon content.

[0028] Reservoir gas content identification module: For shale samples of unknown reservoir type belonging to the same block, obtain the organic carbon content of the shale sample of unknown reservoir type, and identify the reservoir type of the shale sample of unknown reservoir type by comparing it with the shale reservoir type classification standard based on organic carbon content.

[0029] The following are further optimizations and / or improvements to the second technical solution of the above invention:

[0030] The above-mentioned total gas content acquisition module includes a total gas content calculation unit.

[0031] The total gas content calculation unit is used to calculate the total gas content of the shale in the Jimsar block or the Santanghu block. The total gas content is calculated using the following formula:

[0032] When K = 0.0115P - 0.0153, Q = 33.572 (T2 / T1). -0.583 ;

[0033] When K = 0.0013P 2.975 At that time, Q = 0.6228TOC - 0.2952;

[0034] When K=0.0089e 0.6922P At that time, Q = 1.3803TOC - 4.0148;

[0035] In the formula: K is the permeability of the shale sample, mD; P is the porosity of the shale sample, %; Q is the total gas content of the shale gas sample at the same well depth as the shale sample, m. 3 / t; TOC is the organic carbon content of the shale sample, %; T2 is the maximum total hydrocarbon value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %; T1 is the total hydrocarbon base value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %.

[0036] The aforementioned first classification standard module includes a first drawing unit.

[0037] First plotting unit: plots a scatter plot of porosity and total gas content for several shale samples of known reservoir types, with porosity as the horizontal axis and total gas content as the vertical axis.

[0038] The aforementioned second classification standard module includes a second drawing unit.

[0039] The second plotting unit: The scatter plot of the organic carbon content and total gas content is plotted with the total gas content as the horizontal axis and the organic carbon content as the vertical axis.

[0040] The third technical solution of the present invention is achieved through the following measures: an electronic device, including a processor and a memory, wherein the memory stores a computer program, and the computer program is loaded and executed by the processor to realize the method for obtaining gas content of shale gas while drilling as described in the first technical solution.

[0041] The fourth technical solution of the present invention is achieved by the following measures: a storage medium storing a computer program that can be read by a computer, the computer program being configured to execute the method for obtaining gas content in shale gas while drilling as described in the first technical solution.

[0042] One of the key technical points of this invention is the ability to determine the total gas content of shale gas during drilling. Compared to the traditional, precise but costly method of analyzing gas content in a closed core laboratory, this method eliminates the need to send core samples to the laboratory, significantly reducing costs and enabling large-scale on-site evaluation during drilling. Simultaneously, it overcomes the slow process of traditional methods, providing real-time gas content data for development wells and rapidly acquiring results during drilling. This provides timely and crucial information for subsequent development decisions, greatly improving exploration and development efficiency, reducing time wasted waiting for analysis results, and effectively promoting shale gas exploration and development towards high efficiency and low cost, providing technical support for the rational development and utilization of shale gas resources. Furthermore, another key technical point of this invention is the establishment of a shale reservoir type classification standard based on organic carbon content, using the relationship between the total gas content and organic carbon content. This provides a new method for the rapid identification of shale gas reservoir types. Attached Figure Description

[0043] Appendix Figure 1 This is a scatter plot of permeability, porosity, total gas content, and total hydrocarbon peak-to-base ratio for block AA.

[0044] Appendix Figure 2 This is one of the scatter plots showing the permeability, porosity, total gas content, and TOC of block AA.

[0045] Appendix Figure 3 This is the second scatter plot of permeability, porosity, total gas content, and TOC for block AA.

[0046] Appendix Figure 4 This is a scatter plot of the total gas content and well logging porosity in block AA.

[0047] Appendix Figure 5 This is a scatter plot of TOC versus total gas content for block AA. Detailed Implementation

[0048] The present invention is not limited to the following embodiments, and the specific implementation can be determined according to the technical solution of the present invention and the actual situation.

[0049] In this invention, it should be noted that the terms "first," "second," etc., are used only for the convenience of describing this invention and simplifying the description, and are not intended to indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of this invention.

[0050] Unless otherwise specified, all percentages in this invention refer to mass percentages.

[0051] The total hydrocarbon peak-to-base ratio (Ys) is the ratio of the total hydrocarbon peak value to the total hydrocarbon base value. The total hydrocarbon peak value refers to the highest concentration of hydrocarbon gas detected during gas logging.

[0052] In this invention, the porosity can be the porosity of drilling cuttings as described in the patent document with publication number CN119164823A (title: Method for obtaining porosity of drilling cuttings).

[0053] In the existing technology, the most accurate method for determining gas content is to use closed coring, and then quickly send the core samples to the laboratory for analysis. This method is costly, not suitable for large-scale on-site evaluation of shale gas content, and the process is slow, which has significant limitations for real-time evaluation of development wells.

[0054] The present invention will be further described below with reference to embodiments:

[0055] Example 1: A method for obtaining gas content in shale gas during drilling, comprising:

[0056] Porosity and organic carbon content were obtained from shale samples of several known reservoir types;

[0057] Based on the porosity and organic carbon content of shale samples of several known reservoir types, the corresponding total gas content is calculated;

[0058] Scatter plots of porosity and total gas content were drawn for shale samples of several known reservoir types, and a reservoir type classification standard based on porosity and total gas content was established.

[0059] Based on the reservoir type classification standard based on porosity and gas content, the total gas content range corresponding to each category of the reservoir type classification standard is obtained.

[0060] A scatter plot of organic carbon content versus total gas content is established. Based on the total gas content range corresponding to each category of the reservoir type classification standard, the organic carbon content corresponding to each category of the reservoir type classification standard is obtained, thereby establishing a shale reservoir type classification standard based on organic carbon content.

[0061] For shale samples belonging to the same block with unknown reservoir types, obtain the organic carbon content of the shale samples with unknown reservoir types, and identify the reservoir type of the shale samples with unknown reservoir types by comparing them with the shale reservoir type classification standard based on organic carbon content.

[0062] Example 2: As an optimization of the above examples, the total gas content of the Jimsar block shale or the Santanghu block shale is calculated using the following formula:

[0063] When K = 0.0115P - 0.0153, Q = 33.572 (T2 / T1). -0.583 ;

[0064] When K = 0.0013P 2.975 At that time, Q = 0.6228TOC - 0.2952;

[0065] When K=0.0089e 0.6922P At that time, Q = 1.3803TOC - 4.0148;

[0066] In the formula: K is the permeability of the shale sample, mD; P is the porosity of the shale sample, %; Q is the total gas content of the shale gas sample at the same well depth as the shale sample, m³. 3 / t; TOC is the organic carbon content of the shale sample, %; T2 is the maximum total hydrocarbon value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %; T1 is the total hydrocarbon value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %

[0067] If K and P do not satisfy the above relationship, the total gas content shall be obtained by existing methods, such as by using closed core sampling to measure the total gas content of the core sample.

[0068] As can be seen from the formula for calculating total gas content, organic carbon content is the independent variable for calculating total gas content. Therefore, after establishing a scatter plot of organic carbon content versus total gas content, the organic carbon content corresponding to the total gas content range for each category of reservoir type classification standard can be obtained. Thus, the organic carbon content corresponding to each category of reservoir type classification standard can be obtained.

[0069] Higher porosity allows gas to accumulate more easily in the reservoir, resulting in a relatively higher formation gas content (i.e., the total gas content of this application). Permeability refers to the ability of gas to flow within a reservoir. Higher permeability means faster gas migration within the reservoir, leading to a relatively higher formation gas content (i.e., the total gas content of this application). Therefore, the total gas content is related to both porosity and permeability.

[0070] Based on the correlation between total gas content and porosity and permeability, data fitting was performed using the permeability, porosity, T1, T2, organic carbon content, and total gas content measurements of several shale samples, as well as the total gas content measurements of shale samples taken from sealed cores at the same well depth as the shale samples. The goodness of fit (Rfit) was used to determine the optimal data. 2 A higher mathematical model is the formula for calculating the final total gas content (details below). A higher goodness of fit means Rfit... 2 Greater than 0.71.

[0071] For example, such as Figure 1 As shown, through data fitting, it was found that when porosity and permeability satisfy K=0.0115P-0.0153, the total gas content and T1, T2, and organic carbon content satisfy: Q=33.572(T2 / T1). -0.583 .

[0072] like Figure 2 As shown, when porosity and permeability satisfy K=0.0013P2.975 At that time, the total gas content and organic carbon content satisfy: Q=0.6228TOC-0.2952.

[0073] like Figure 3 As shown, when porosity and permeability satisfy K=0.0089e 0.6922P At that time, the total gas content and organic carbon content satisfy: Q=1.3803TOC-4.0148.

[0074] Since measuring the total gas content using sealed cored shale samples is costly, after obtaining the above formula for calculating the total gas content, the corresponding formula can be selected based on the relationship between porosity and permeability to calculate the total gas content.

[0075] During gas logging, the total hydrocarbon curve is a crucial tool for field logging technicians to detect and interpret anomalies in oil and gas. Under normal drilling conditions, if the encountered formation lithology is stable and the fluid properties within the formation remain unchanged, the total hydrocarbon content will be relatively stable during logging, and the fluctuation range of the total hydrocarbon curve will be small. However, due to various factors such as drilling conditions, changes in formation fluid pressure, and variations in the total hydrocarbon content, abnormal changes in the total hydrocarbon curve can easily occur.

[0076] Gas measurement anomaly

[0077] This refers to the phenomenon where, when encountering oil and gas reservoirs, the total hydrocarbon content significantly increases compared to the background gas logging value (i.e., the total hydrocarbon base value or baseline concentration) due to gas infiltrating or diffusing into the drilling fluid from fractured rock layers and formations. Gas logging anomalies are the most direct logging parameter characteristics for discovering oil and gas reservoirs. The maximum total hydrocarbon value in the gas logging anomaly segment is the maximum total hydrocarbon value in the gas logging anomaly segment on the total hydrocarbon logging curve.

[0078] Normally, total hydrocarbon logging data remains stable within a certain range with minimal fluctuations; this value is called the total hydrocarbon baseline value. When real-time logging data rises to more than 1.5 times the baseline value, it is called a total hydrocarbon logging anomaly, which is reflected in the logging curve as an increase in the curve amplitude of more than 1.5 times. The total hydrocarbon baseline value of the gas logging anomaly segment is the total hydrocarbon baseline value of the gas logging anomaly segment on the total hydrocarbon logging curve.

[0079] Example 3: As an optimization of the above example, a scatter plot of porosity and total gas content of shale samples of several known reservoir types is drawn, with porosity as the horizontal axis and total gas content as the vertical axis.

[0080] Example 4: As an optimization of the above embodiment, the scatter plot of organic carbon content versus total gas content is plotted with total gas content on the horizontal axis and organic carbon content on the vertical axis.

[0081] Example 5: An apparatus for obtaining gas content in shale gas during drilling as described in the above examples, comprising:

[0082] Porosity and Organic Carbon Content Acquisition Module: Acquires the porosity and organic carbon content of shale samples from several known reservoir types;

[0083] Total gas content acquisition module: Calculates the corresponding total gas content based on the porosity and organic carbon content of shale samples of several known reservoir types;

[0084] First classification standard module: Draw scatter plots of porosity and total gas content of shale samples of several known reservoir types, and establish a reservoir type classification standard based on porosity and total gas content;

[0085] Total gas content range acquisition module: Based on the reservoir type classification standard based on porosity and gas content, the total gas content range corresponding to each category of the reservoir type classification standard is obtained;

[0086] The second classification standard module: establishes a scatter plot of the organic carbon content and total gas content, obtains the organic carbon content corresponding to each category of the reservoir type classification standard according to the total gas content range of each category, and thus establishes a shale reservoir type classification standard based on organic carbon content.

[0087] Reservoir gas content identification module: For shale samples of unknown reservoir type belonging to the same block, obtain the organic carbon content of the shale sample of unknown reservoir type, and identify the reservoir type of the shale sample of unknown reservoir type by comparing it with the shale reservoir type classification standard based on organic carbon content.

[0088] Example 6: As an optimization of the above embodiments, the total gas content calculation unit includes a total gas content calculation subunit.

[0089] The total gas content calculation subunit is used to calculate the total gas content of the shale in the Jimsar block or the Santanghu block. The total gas content is calculated using the following formula:

[0090] When K = 0.0115P - 0.0153, Q = 33.572 (T2 / T1). -0.583 ;

[0091] When K = 0.0013P 2.975 At that time, Q = 0.6228TOC - 0.2952;

[0092] When K=0.0089e 0.6922P At that time, Q = 1.3803TOC - 4.0148;

[0093] In the formula: K is the permeability of the shale sample, mD; P is the porosity of the shale sample, %; Q is the total gas content of the shale gas sample at the same well depth as the shale sample, m³. 3 / t; TOC is the organic carbon content of the shale sample, %; T2 is the maximum total hydrocarbon value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %; T1 is the total hydrocarbon base value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %.

[0094] Example 7: As an optimization of Example 5 above, the first classification standard module includes a first drawing unit.

[0095] First plotting unit: plots a scatter plot of porosity and total gas content for several shale samples of known reservoir types, with porosity as the horizontal axis and total gas content as the vertical axis.

[0096] Example 8: As an optimization of Example 5 above, the second classification standard module includes a second drawing unit.

[0097] The second plotting unit: The scatter plot of the organic carbon content and total gas content is plotted with the total gas content as the horizontal axis and the organic carbon content as the vertical axis.

[0098] Example 9: An electronic device includes a processor and a memory, wherein the memory stores a computer program, which is loaded and executed by the processor to implement the method for obtaining gas content in shale gas during drilling as described in the above examples.

[0099] Example 10: A storage medium storing a computer program that can be read by a computer, the computer program being configured to execute, when running, the method for obtaining gas content in shale gas during drilling as described in the above examples.

[0100] Example 11: Taking the Jimsar block shale as an example, the method for obtaining gas content in shale gas during drilling described in this invention is explained.

[0101] 1) Here, the total gas content of shale gas mainly includes adsorbed gas and free gas, based on the three forms of change in permeability and porosity ( Figures 1 to 3 Using TOC and the peak base ratio of total hydrocarbons measured by gas chromatography, scatter plots of the corresponding total gas content versus the peak base ratio of total hydrocarbons were established. Figure 1 (Right figure), scatter plot of total gas content versus TOC ( Figures 2 to 3 (The image on the right).

[0102] Depend on Figure 1 It can be seen that the correlation between permeability and porosity is a linear positive correlation. Figure 1 (Left figure), but the correlation between the total gas content (permeability and porosity) and the total hydrocarbon peak ratio is negative. Figure 1 (The image on the right).

[0103] Depend on Figures 2 to 3 As can be seen, the correlation between permeability and porosity is basically positive. Figures 2 to 3 The left figure shows that the total gas content (permeability and porosity) is linearly positively correlated with TOC. Figures 2 to 3 (The right image), especially Figure 2 In the right figure, the goodness of fit of the fitting formula between total gas content and TOC is as high as 0.919, indicating that the total gas content and TOC are highly positively correlated.

[0104] The positive correlation between total gas content and total organic carbon (TOC) provides a basis for establishing a classification standard for shale reservoir types based on organic carbon content using TOC as a parameter.

[0105] 2) Combining the reservoir type interpreted from well logging, and using the total gas content and well logging porosity, plot a scatter plot of porosity versus total gas content (e.g., ...). Figure 4 ), and establish reservoir type classification standards based on porosity and total gas content (see Table 1);

[0106] The total gas content is calculated using the following formula:

[0107] When K = 0.0115P - 0.0153, Q = 33.572 (T2 / T1). -0.583 ;

[0108] When K = 0.0013P 2.975 At that time, Q = 0.6228TOC - 0.2952;

[0109] When K=0.0089e 0.6922P At that time, Q = 1.3803TOC - 4.0148;

[0110] In the formula: K is the permeability of the shale sample, mD; P is the porosity of the shale sample, %; Q is the total gas content of the shale gas sample at the same well depth as the shale sample, m³. 3 / t; TOC is the organic carbon content of the shale sample, %; T2 is the maximum total hydrocarbon value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %; T1 is the total hydrocarbon base value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %.

[0111] 3) Based on the reservoir type interpreted from well logging (Table 1), the total gas content and TOC are cross-referenced. Figure 5 ). Figure 5The study found that, except for six shale samples from Class I reservoirs with a TOC of less than or equal to 3.5%, the TOC of most other Class I shale samples was greater than 3.5%. Except for one shale sample from Class II reservoirs with a TOC greater than 5%, the TOC of the remaining Class II-III shale samples ranged from 2.0% to 3.5%. Therefore, based on TOC, shale was classified into three categories: good oil-generating rocks, medium oil-generating rocks, and poor oil-generating rocks. A classification standard for shale reservoir types based on organic carbon content was established (Table 2). At the same time, an organic carbon TOC of 2% was set as the lower limit for whether there is industrial production capacity.

[0112] The above technical features constitute various embodiments of the present invention, which have strong adaptability and implementation effect. Unnecessary technical features can be added or removed according to actual needs to meet the needs of different situations.

[0113] Table 1

[0114] .

[0115] Table 2

[0116] .

Claims

1. A method for obtaining gas content in shale gas during drilling, characterized in that, include: Porosity and organic carbon content were obtained from shale samples of several known reservoir types; Based on the porosity and organic carbon content of shale samples of several known reservoir types, the corresponding total gas content is calculated; Scatter plots of porosity and total gas content were drawn for shale samples of several known reservoir types, and a reservoir type classification standard based on porosity and total gas content was established. Based on the reservoir type classification standard based on porosity and gas content, the total gas content range corresponding to each category of the reservoir type classification standard is obtained. A scatter plot of organic carbon content versus total gas content is established. Based on the total gas content range corresponding to each category of the reservoir type classification standard, the organic carbon content corresponding to each category of the reservoir type classification standard is obtained, thereby establishing a shale reservoir type classification standard based on organic carbon content. For shale samples of unknown reservoir type belonging to the same block, obtain the organic carbon content of the shale samples of unknown reservoir type, and identify the reservoir type of the shale samples of unknown reservoir type by referring to the shale reservoir type classification standard based on organic carbon content. For the Jimsar block shale or the Santanghu block shale, the total gas content is calculated using the following formula: When K = 0.0115P - 0.0153, Q = 33.572 (T2 / T1). -0.583 ; When K = 0.0013P 2.975 At that time, Q = 0.6228TOC - 0.2952; When K=0.0089e 0.6922P At that time, Q = 1.3803TOC - 4.0148; In the formula: K is the permeability of the shale sample, mD; P is the porosity of the shale sample, %; Q is the total gas content of the shale gas sample at the same well depth as the shale sample, m³. 3 / t; TOC represents the organic carbon content of the shale sample, % T2 represents the maximum total hydrocarbon value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %; T1 represents the total hydrocarbon base value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %.

2. The method for obtaining gas content in shale gas during drilling according to claim 1, characterized in that, A scatter plot of porosity versus total gas content for shale samples of several known reservoir types is drawn, with porosity as the abscissa and total gas content as the ordinate. Or / and, the scatter plot of the organic carbon content versus the total gas content is plotted with the total gas content on the x-axis and the organic carbon content on the y-axis.

3. An apparatus for applying the method for obtaining gas content in shale gas during drilling as described in any one of claims 1 to 2, characterized in that, include: Porosity and Organic Carbon Content Acquisition Module: Acquires the porosity and organic carbon content of shale samples from several known reservoir types; Total gas content acquisition module: Calculates the corresponding total gas content based on the porosity and organic carbon content of shale samples of several known reservoir types; First classification standard module: Draw scatter plots of porosity and total gas content of shale samples of several known reservoir types, and establish a reservoir type classification standard based on porosity and total gas content; Total gas content range acquisition module: Based on the reservoir type classification standard based on porosity and gas content, the total gas content range corresponding to each category of the reservoir type classification standard is obtained; The second classification standard module: establishes a scatter plot of the organic carbon content and total gas content, obtains the organic carbon content corresponding to each category of the reservoir type classification standard according to the total gas content range of each category, and thus establishes a shale reservoir type classification standard based on organic carbon content. Reservoir gas content identification module: For shale samples of unknown reservoir type belonging to the same block, obtain the organic carbon content of the shale sample of unknown reservoir type, and identify the reservoir type of the shale sample of unknown reservoir type by comparing it with the shale reservoir type classification standard based on organic carbon content.

4. The apparatus according to claim 3, characterized in that, The total gas content acquisition module includes a total gas content calculation unit. The total gas content calculation unit is used to calculate the total gas content of the shale in the Jimsar block or the Santanghu block. The total gas content is calculated using the following formula: When K = 0.0115P - 0.0153, Q = 33.572 (T2 / T1). -0.583 ; When K = 0.0013P 2.975 At that time, Q = 0.6228TOC - 0.2952; When K=0.0089e 0.6922P At that time, Q = 1.3803TOC - 4.0148; In the formula: K is the permeability of the shale sample, mD; P is the porosity of the shale sample, %; Q is the total gas content of the shale gas sample at the same well depth as the shale sample, m³. 3 / t; TOC represents the organic carbon content of the shale sample, % T2 represents the maximum total hydrocarbon value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %; T1 represents the total hydrocarbon base value of the gas anomaly segment of the shale gas sample at the same well depth as the shale sample, %.

5. The apparatus according to claim 3 or 4, characterized in that, A scatter plot of porosity versus total gas content for shale samples of several known reservoir types is drawn, with porosity as the abscissa and total gas content as the ordinate. Or / and, the scatter plot of the organic carbon content versus the total gas content is plotted with the total gas content on the x-axis and the organic carbon content on the y-axis.

6. An electronic device, characterized in that, It includes a processor and a memory, wherein the memory stores a computer program, which is loaded and executed by the processor to implement the method for obtaining gas content in shale gas during drilling as described in any one of claims 1 to 2.

7. A storage medium, characterized in that, The storage medium stores a computer program that can be read by a computer, and the computer program is configured to execute the method for obtaining gas content in shale gas during drilling as described in any one of claims 1 to 2.

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