A method for identifying natural gas source

Abstract

This invention discloses a method for identifying natural gas sources, comprising the following steps: S1: collecting data on natural gas with clearly defined sources and corresponding source rock data in the study area; S2: obtaining the natural gas type to be identified; S3: calculating the natural gas maturity of the natural gas to be identified; S4: comparing the natural gas type with the source rock organic matter type, and comparing the natural gas maturity with the source rock organic matter thermal maturity; if the comparison results show only one corresponding source rock, then it is the source of the natural gas to be identified; otherwise, proceed to step S5; S5: comparing ethane carbon isotopes with source rock organic carbon isotopes, comparing natural gas components with residual gas components, and comparing natural gas isotopes with residual gas isotopes; S6: obtaining the source of the natural gas to be identified based on the comparison results of S4 and S5. This invention can quickly identify and obtain natural gas sources, providing technical support for natural gas exploration and development.

Description

Technical Field

[0001] The invention relates to the technical field of oil and natural gas exploration, and in particular to a method for identifying a natural gas source. Background Art

[0002] Natural gas source analysis is the key content of oil and gas accumulation. Distinguishing the source of natural gas helps provide key information for exploration decisions. In particular, during the formation drilling process, there are many natural gas displays in different layers and many cases of casing gas leakage after cementing. Real-time identification of natural gas sources can provide a basic basis for drilling plan adjustment and drilling safety.

[0003] At present, conventional gas source comparison methods mainly rely on biomarker compounds and natural gas carbon and hydrogen isotopes. For biomarker compounds, it is necessary to extract saturated hydrocarbons, aromatic hydrocarbons, asphaltene and non-hydrocarbon components from source rocks, reservoir asphalt or crude oil, and analyze one of the components for biomarker compounds to establish the relationship between source rocks and reservoir asphalt / crude oil. However, this comparison method requires rock samples or crude oil as the research basis, and the analysis time is long and is easily affected by maturity, which obviously does not meet the needs of rapid gas source analysis.

[0004] In addition, for natural gas carbon and hydrogen isotopes, current research is to analyze the gas source to obtain the carbon and hydrogen isotopes of methane, ethane and propane, and then project the data on the empirical map for analysis. However, the comparison of the map is still done manually, which greatly slows down the process, and a unified natural gas database has not been established, which leads to incomplete use of previous data in the comparison, and it is impossible to automatically identify and quickly compare the source of natural gas. Summary of the invention

[0005] In view of the above problems, the present invention aims to provide a method for identifying the source of natural gas.

[0006] The technical solution of the present invention is as follows:

[0007] A method for identifying a natural gas source comprises the following steps:

[0008] S1: Collect natural gas data with clear sources and corresponding source rock data in the study area, and use them to establish a database for the study area;

[0009] The natural gas data includes natural gas components and natural gas isotopes, and the natural gas isotopes include methane carbon isotopes, ethane carbon isotopes, propane carbon isotopes, methane hydrogen isotopes, and ethane hydrogen isotopes;

[0010] The source rock data include source rock organic matter thermal maturity, source rock organic matter type, source rock organic carbon isotope, retained gas component and retained gas isotope, and the retained gas isotope is the same as the isotope included in the natural gas isotope;

[0011] S2: collecting natural gas data of the natural gas to be identified in the study area, and performing natural gas genesis analysis based on the natural gas data of the natural gas to be identified to obtain the natural gas type of the natural gas to be identified;

[0012] S3: calculating the natural gas maturity of the natural gas to be identified according to the natural gas type of the natural gas to be identified;

[0013] S4: comparing the natural gas type of the natural gas to be identified with the organic matter type of the source rock in the database; comparing the natural gas maturity of the natural gas to be identified with the thermal maturity of the organic matter in the source rock in the database;

[0014] If the comparison results of the two only show one corresponding source rock, then the source rock is the gas source of the natural gas to be identified;

[0015] Otherwise, go to step S5;

[0016] S5: comparing the ethane carbon isotope of the natural gas to be identified with the organic carbon isotope of the source rock in the database; comparing the natural gas components of the natural gas to be identified with the retained gas components in the database; comparing the natural gas isotopes of the natural gas to be identified with the retained gas isotopes in the database;

[0017] S6: According to the comparison results of step S4 and step S5, the gas source of the natural gas to be identified is obtained.

[0018] Preferably, in step S2, a natural gas type identification mathematical model is used to perform natural gas genesis analysis.

[0019] Preferably, the natural gas type identification mathematical model includes:

[0020] (1)δ 13 Mathematical model for identifying natural gas types based on C1-δD1

[0021] Let x = δ 13 C1, represents the carbon isotope of methane; y = δD1, represents the hydrogen isotope of methane; the δ 13 The mathematical model for natural gas type identification based on C1-δD1 is:

[0022]

[0023]

[0024] Where: Ω1(x, y) is the marine sapropelic area; Ω2(x, y) is the coal-bearing source rock area;

[0025] (2)δ 13 Mathematical model for identifying natural gas types based on C2-δD1

[0026] Let x = δ 13 C2, represents ethane carbon isotope; y = δD1; the δ 13 The mathematical model for natural gas type identification of C2-δD1 is:

[0027]

[0028]

[0029] (3)δ 13 C1-δ 13 Mathematical model for identifying natural gas types based on C2

[0030] Let x = δ 13 C1;y=δ 13 C2; said δ 13 C1-δ 13 The mathematical model for natural gas type identification of C2 is:

[0031] Ω3(x,y)={(x,y)|-28≤y≤-24,xy≤0} (5)

[0032] Ω4(x,y)={(x,y)|-30≤y≤-28,xy≤0} (6)

[0033] Ω5(x,y)={(x,y)|-36≤y≤-30,xy≤0} (7)

[0034] Where: Ω3(x,y) is the coal-type gas area; Ω4(x,y) is the mixed gas area; Ω5(x,y) is the oil-type gas area;

[0035] (4) Mathematical model for distinguishing kerogen degradation gas and crude oil cracking gas based on ln(C1 / C2)-ln(C2 / C3)

[0036] Assume x=ln(C1 / C2), where C1 represents the methane content and C2 represents the ethane content; y=ln(C2 / C3), where C3 represents the propane content; the mathematical model for distinguishing kerogen degradation gas and crude oil cracking gas of ln(C1 / C2)-ln(C2 / C3) is:

[0037] f1(x,y)=160.1·sin(0.0057x-0.0021)+0.877·sin(1.139x+2.498)-y(8)

[0038]

[0039] When f1(x,y)>0 and f2(x,y)<0, it is kerogen degradation gas; when f2(x,y≥0, it is crude oil cracking gas;

[0040] (5)δ 13 C1-C1 / C 2+3 Mathematical model for natural gas type identification

[0041] Let x = δ 13 C1;y=C1 / C 2+3 , where C 2+3 Indicates the content of ethane and propane; the δ 13 C1-C1 / C 2+3 The mathematical model for natural gas type identification is:

[0042] Ω6(x,y)={(x,y)|350≤y≤100000,-100≤x≤-52,xy+49.67y+1867≤0}(10)

[0043]

[0044] Where: Ω6(x,y) is the biogenic gas area; Ω7(x,y) is the thermogenic gas area;

[0045] (6)δ 13 C2-δ 13 Mathematical model for natural gas type identification based on C1

[0046] Let x = δ 13 C2;y=δ 13 C1; the δ 13 C2-δ 13 The mathematical model for natural gas type identification of C1 is:

[0047]

[0048]

[0049]

[0050] Ω 11 (x,y)={(x,y)|-29≤x≤-28,-44≤y≤-30} (15)

[0051] Ω12 (x,y)={(x,y)|-50≤x≤-15,-55≤y≤-15,9.29xy≤3.07}-Ω 10 (x,y)(16)

[0052] Where: Ω8(x,y) is region I; Ω9(x,y) is region II; Ω 10 (x,y) is region III; Ω 11 (x, y) is the IV region; Ω 12 (x,y) is a blank area;

[0053] (7)δ 13 C3-δ 13 Mathematical model for natural gas type identification based on C1

[0054] Let x = δ 13 C3, represents propane carbon isotope; y = δ 13 C1; the δ 13 C3-δ 13 The mathematical model for natural gas type identification of C1 is:

[0055]

[0056]

[0057]

[0058] Ω 11 (x,y)={(x,y)|-29≤x≤-28,-44≤y≤-30} (20)

[0059] Ω 12 (x,y)={(x,y)|-40≤x≤-15,-55≤y≤-15,9.29xy≤3.07}-Ω 10 (x,y)(21).

[0060] Preferably, in step S3, when the natural gas to be identified is oil-type gas, the natural gas maturity is calculated using the following formula:

[0061] δ 13 C1≈15.80lgRo natural gas -42.20 (22)

[0062] When the natural gas to be identified is coal-type gas, the natural gas maturity is calculated using the following formula:

[0063] δ 13 C1≈14.12lgRo natural gas -34.39 (23)

[0064] Where: 13 C1 represents the carbon isotope of methane; Ro natural gas Indicates the maturity of natural gas.

[0065] Preferably, in step S4 and step S5, when performing the comparison, similarity calculation or pattern matching method is used for comparative analysis.

[0066] Preferably, in step S4, when the natural gas type of the natural gas to be identified is compared with the organic matter type of the source rock in the database, type I and type II1 in the source rock correspond to oil-type gas in the natural gas; type II2 in the source rock corresponds to oil-type gas-coal-type gas in the natural gas; and type III in the source rock corresponds to coal-type gas in the natural gas.

[0067] Preferably, in step S4, when comparing the natural gas maturity of the natural gas to be identified with the thermal maturity of organic matter in the source rock in the database, the following formula is used for identification:

[0068]

[0069] Where: Layers represents potential source rock; i represents potential source rock layer; M represents the total number of potential source rock layers; N represents the total number of source rock Ro data in the i-th layer; represents the jth Ro data in the i-th source rock layer; Ro natural gas Indicates the maturity of the natural gas to be identified.

[0070] Preferably, in step S5, when comparing the ethane carbon isotope of the natural gas to be identified with the organic carbon isotope of the source rock in the database, the following formula is used for identification:

[0071]

[0072] Where: represents the organic carbon isotope of the jth sample in the i-th layer of source rock; Represents the carbon isotope of natural gas ethane to be identified.

[0073] Preferably, in step S5, when comparing the natural gas components of the natural gas to be identified with the retained gas components in the database, the following formula is used for identification:

[0074]

[0075] Where: Dc represents the dryness coefficient of the jth natural gas data in the i-th source rock layer; natural gasIndicates the natural gas dryness factor (ratio of methane to methane and its higher alkanes); represents the N2 content of the jth natural gas data in the i-th source rock layer; N 2natural gas Indicates the N2 content in the natural gas to be identified; represents the CO2 content of the jth natural gas data in the i-th source rock layer; CO 2natural gas Indicates the CO2 content in the natural gas to be identified; represents the He content of the jth natural gas data in the i-th source rock layer; He natural gas Indicates the He content in the natural gas to be identified; represents the H2 content of the jth natural gas data in the i-th layer of source rock; H 2natural gas Indicates the H2 content in the natural gas to be identified;

[0076] When comparing the natural gas isotopes of the natural gas to be identified with the isotopes of the retained gas in the database, the following formula is used for identification:

[0077]

[0078] Where: represents the jth natural gas data in the i-th source rock layer 13 C C2H6 value; Indicates the δ 13 C C2H6 .

[0079] Preferably, in step S6, when the gas source of the natural gas to be identified is obtained based on the comparison results of step S4 and step S5, a weight is assigned to each comparison result, and the weight of the result of comparing ethane carbon isotopes with source rock organic carbon isotopes, the weight of the result of comparing natural gas with retained gas, the weight of the result of comparing natural type with source rock organic matter type, and the weight of the result of comparing natural gas maturity with source rock organic matter thermal maturity decreases in sequence.

[0080] The beneficial effects of the present invention are:

[0081] The present invention can quickly identify the natural gas type of the natural gas to be identified by using a natural gas type identification mathematical model, and can quickly identify the natural gas source of the natural gas to be identified by comparing natural gas data with source rock data. BRIEF DESCRIPTION OF THE DRAWINGS

[0082] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative labor.

[0083] Figure 1 A schematic flow chart of a method for identifying a natural gas source according to the present invention;

[0084] Figure 2 In a specific embodiment, 13 Schematic diagram of the recognition results of the mathematical model for natural gas type identification of C1-δD1;

[0085] Figure 3 In a specific embodiment, 13 Schematic diagram of the identification results of the mathematical model for natural gas type identification of C2-δD1;

[0086] Figure 4 In a specific embodiment, 13 C1-δ 13 Schematic diagram of the recognition results of the mathematical model for natural gas type identification of C2;

[0087] Figure 5 It is a schematic diagram of the recognition result of the natural gas type identification mathematical model of ln(C1 / C2)-ln(C2 / C3) in a specific embodiment;

[0088] Figure 6 In a specific embodiment, 13 C1-C1 / C 2+3 Schematic diagram of the identification results of the mathematical model for natural gas type identification;

[0089] Figure 7 In a specific embodiment, 13 C2-δ 13 C1 and δ 13 C3-δ 13 Schematic diagram of the recognition results of the mathematical model for natural gas type identification of C1. DETAILED DESCRIPTION

[0090] The present invention is further described below in conjunction with the accompanying drawings and embodiments. It should be noted that, in the absence of conflict, the embodiments in this application and the technical features in the embodiments can be combined with each other. It should be noted that, unless otherwise specified, all technical and scientific terms used in this application have the same meanings as those generally understood by those of ordinary skill in the art to which this application belongs. The words "including" or "comprising" and the like used in the disclosure of the present invention mean that the elements or objects appearing before the word cover the elements or objects listed after the word and their equivalents, without excluding other elements or objects.

[0091] like Figure 1 As shown, the present invention provides a method for identifying a natural gas source, comprising the following steps:

[0092] S1: Collect natural gas data and corresponding source rock data with clear sources in the study area, and use them to establish a database for the study area.

[0093] In a specific embodiment, the natural gas data includes natural gas components (CH4, C2H6, C3H8, CO2, N2, He, H2, etc.) and natural gas isotopes, wherein the natural gas isotopes include methane carbon isotopes (δ 13 C1 naturalgas ), ethane carbon isotopes (δ 13 C 2naturalgas ), propane carbon isotopes (δ 13 C 3naturalgas ), methane hydrogen isotopes (δD 1naturalgas ), ethane hydrogen isotopes (δD 2naturalgas );

[0094] The source rock data include source rock organic matter thermal maturity (Ro), source rock organic matter type (I, II1, II2 and III), source rock organic carbon isotope (δ 13 C orgsourcerock ), retained gas components (CH4, C2H6, C3H8, CO2, N2, He, H2, etc.) and retained gas isotopes, wherein the retained gas isotopes are the same as the isotopes included in the natural gas isotopes (i.e., the retained gas isotopes include δ 13 C1 sourcerock , δ 13 C 2sourcerock , δ 13 C3 sourcerock ,δD1 sourcerock ,δD 2source rock ).

[0095] S2: Collecting natural gas data of the natural gas to be identified in the study area, and performing natural gas genesis analysis based on the natural gas data of the natural gas to be identified to obtain the natural gas type of the natural gas to be identified.

[0096] In a specific embodiment, a natural gas type identification mathematical model is used to perform natural gas genesis analysis. Optionally, the natural gas type identification mathematical model includes:

[0097] (1)δ 13 Mathematical model for identifying natural gas types based on C1-δD1

[0098] Let x = δ 13 C1, represents the carbon isotope of methane; y = δD1, represents the hydrogen isotope of methane; the δ 13 The mathematical model for natural gas type identification based on C1-δD1 is:

[0099]

[0100]

[0101] Where: Ω1(x, y) is the marine sapropelic area; Ω2(x, y) is the coal-bearing source rock area;

[0102] (2)δ 13 Mathematical model for identifying natural gas types based on C2-δD1

[0103] Let x = δ 13 C2, represents ethane carbon isotope; y = δD1; the δ 13 The mathematical model for natural gas type identification of C2-δD1 is:

[0104]

[0105]

[0106] (3)δ 13 C1-δ 13 Mathematical model for identifying natural gas types based on C2

[0107] Let x = δ 13 C1;y=δ 13 C2; said δ 13 C1-δ 13 The mathematical model for natural gas type identification of C2 is:

[0108] Ω3(x,y)={(x,y)|-28≤y≤-24,xy≤0} (5)

[0109] Ω4(x,y)={(x,y)|-30≤y≤-28,xy≤0} (6)

[0110] Ω5(x,y)={(x,y)|-36≤y≤-30,xy≤0} (7)

[0111] Where: Ω3(x,y) is the coal-type gas area; Ω4(x,y) is the mixed gas area; Ω5(x,y) is the oil-type gas area;

[0112] (4) Mathematical model for distinguishing kerogen degradation gas and crude oil cracking gas based on ln(C1 / C2)-ln(C2 / C3)

[0113] Assume x=ln(C1 / C2), where C1 represents the methane content and C2 represents the ethane content; y=ln(C2 / C3), where C3 represents the propane content; the mathematical model for distinguishing kerogen degradation gas and crude oil cracking gas of ln(C1 / C2)-ln(C2 / C3) is:

[0114] f1(x,y)=160.1·sin(0.0057x-0.0021)+0.877·sin(1.139x+2.498)-y(8)

[0115]

[0116] When f1(x,y)>0 and f2(x,y)<0, it is kerogen degradation gas; when f2(x,y≥0, it is crude oil cracking gas;

[0117] (5)δ 13 C1-C1 / C 2+3 Mathematical model for natural gas type identification

[0118] Let x = δ 13 C1;y=C1 / C 2+3 , where C 2+3 Indicates the content of ethane and propane; the δ 13 C1-C1 / C 2+3 The mathematical model for natural gas type identification is:

[0119] Ω6(x,y)={(x,y)|350≤y≤100000,-100≤x≤-52,xy+49.67y+1867≤0}(10)

[0120]

[0121] Where: Ω6(x,y) is the biogenic gas area; Ω7(x,y) is the thermogenic gas area;

[0122] (6)δ 13 C2-δ 13Mathematical model for natural gas type identification based on C1

[0123] Let x = δ 13 C2;y=δ 13 C1; the δ 13 C2-δ 13 The mathematical model for natural gas type identification of C1 is:

[0124]

[0125]

[0126]

[0127] Ω 11 (x,y)={(x,y)|-29≤x≤-28,-44≤y≤-30} (15)

[0128] Ω 12 (x,y)={(x,y)|-50≤x≤-15,-55≤y≤-15,9.29xy≤3.07}-Ω 10 (x,y)(16)

[0129] Where: Ω8(x, y) is region I (coal-type gas); Ω9(x, y) is region II (oil-type gas); 10 (x, y) is region III (carbon isotope inversion gas mixture); Ω 11 (x, y) is the IV region (coal-type gas and / or oil-type gas); Ω 12 (x,y) is a blank area;

[0130] (7)δ 13 C3-δ 13 Mathematical model for natural gas type identification based on C1

[0131] Let x = δ 13 C3, represents propane carbon isotope; y = δ 13 C1; the δ 13 C3-δ 13 The mathematical model for natural gas type identification of C1 is:

[0132]

[0133]

[0134]

[0135] Ω 11 (x,y)={(x,y)|-29≤x≤-28,-44≤y≤-30} (20)

[0136] Ω 12 (x,y)={(x,y)|-40≤x≤-15,-55≤y≤-15,9.29xy≤3.07}-Ω 10 (x,y)(21).

[0137] It should be noted that the natural gas type identification mathematical model of the above embodiment is a preferred natural gas genesis analysis method of the present invention, which can more quickly identify the natural gas type of the natural gas to be identified. In addition to the natural gas genesis analysis method of the above embodiment, other natural gas genesis analysis methods in the prior art can also be applied to the present invention.

[0138] S3: Calculating the natural gas maturity of the natural gas to be identified according to the natural gas type of the natural gas to be identified.

[0139] In a specific embodiment, when the natural gas to be identified is oil-type gas, the maturity of the natural gas is calculated using the following formula:

[0140] δ 13 C1≈15.80lgRo natural gas -42.20 (22)

[0141] When the natural gas to be identified is coal-type gas, the natural gas maturity is calculated using the following formula:

[0142] δ 13 C1≈14.12lgRo natural gas -34.39 (23)

[0143] Where: 13 C1 represents the carbon isotope of methane; Ro natural gas Indicates the maturity of natural gas.

[0144] S4: comparing the natural gas type of the natural gas to be identified with the organic matter type of the source rock in the database; comparing the natural gas maturity of the natural gas to be identified with the thermal maturity of the organic matter in the source rock in the database;

[0145] If the comparison results of the two only show one corresponding source rock, then the source rock is the gas source of the natural gas to be identified; otherwise, the process proceeds to step S5.

[0146] In a specific embodiment, when performing the comparison, similarity calculation or pattern matching method is used to perform comparative analysis.

[0147] In a specific embodiment, when the natural gas type of the natural gas to be identified is compared with the organic matter type of the source rock in the database, Type I and Type II1 in the source rock correspond to oil-type gas in the natural gas; Type II2 in the source rock corresponds to oil-type gas-coal-type gas in the natural gas; Type III in the source rock corresponds to coal-type gas in the natural gas.

[0148] When the natural gas maturity of the natural gas to be identified is compared with the thermal maturity of the organic matter in the source rock in the database, the following formula is used for identification:

[0149]

[0150] Where: Layers represents potential source rock; i represents potential source rock layer; M represents the total number of potential source rock layers; N represents the total number of source rock Ro data in the i-th layer; represents the jth Ro data in the i-th source rock layer; Ro natural gas Indicates the maturity of the natural gas to be identified.

[0151] S5: Compare the ethane carbon isotopes of the natural gas to be identified with the organic carbon isotopes of the source rocks in the database; compare the natural gas components of the natural gas to be identified with the retained gas components in the database; compare the natural gas isotopes of the natural gas to be identified with the retained gas isotopes in the database.

[0152] In a specific embodiment, when performing comparison in this step, similarity calculation or pattern matching method is also used for comparative analysis.

[0153] In a specific embodiment, when comparing the ethane carbon isotope of the natural gas to be identified with the organic carbon isotope of the source rock in the database, the following formula is used for identification:

[0154]

[0155] Where: represents the organic carbon isotope of the jth sample in the i-th layer of source rock; Represents the carbon isotope of natural gas ethane to be identified.

[0156] When comparing the natural gas components of the natural gas to be identified with the retained gas components in the database, the following formula is used for identification:

[0157]

[0158] Where: Dc represents the dryness coefficient of the jth natural gas data in the i-th source rock layer; natural gasIndicates the natural gas dryness factor (ratio of methane to methane and its higher alkanes); represents the N2 content of the jth natural gas data in the i-th source rock layer; N 2natural gas Indicates the N2 content in the natural gas to be identified; represents the CO2 content of the jth natural gas data in the i-th source rock layer; CO 2natural gas Indicates the CO2 content in the natural gas to be identified; represents the He content of the jth natural gas data in the i-th source rock layer; He natural gas Indicates the He content in the natural gas to be identified; represents the H2 content of the jth natural gas data in the i-th layer of source rock; H 2natural gas Indicates the H2 content in the natural gas to be identified;

[0159] When comparing the natural gas isotopes of the natural gas to be identified with the isotopes of the retained gas in the database, the following formula is used for identification:

[0160]

[0161] Where: represents the jth natural gas data in the i-th source rock layer value; Indicates the natural gas to be identified

[0162] S6: According to the comparison results of step S4 and step S5, the gas source of the natural gas to be identified is obtained.

[0163] In a specific embodiment, when the gas source of the natural gas to be identified is obtained according to the comparison results of step S4 and step S5, a weight is assigned to each comparison result, and the weight of the result of comparing ethane carbon isotopes with source rock organic carbon isotopes, the weight of the result of comparing natural gas with retained gas, the weight of the result of comparing natural type with source rock organic matter type, and the weight of the result of comparing natural gas maturity with source rock organic matter thermal maturity decreases in sequence.

[0164] In a specific embodiment, the present invention further provides a system for automatically identifying a natural gas source, the system comprising:

[0165] Implementing the step of building a database of the research area in the method for identifying the natural gas source of the present invention;

[0166] Implementing the natural gas origin analysis step of the method for identifying the natural gas source of the present invention;

[0167] Implementing the comparison steps of the method for identifying the natural gas source of the present invention;

[0168] The comparison result output step of the method for identifying the natural gas source described in the present invention is realized.

[0169] In a specific embodiment, the present invention further provides an electronic device, including a memory, a processor, and a computer program stored in the memory and used to run on the processor, and the processor implements the method for identifying the source of natural gas described in the present invention when executing the computer program.

[0170] In a specific embodiment, the present invention further provides a computer storage medium having a computer program stored thereon, wherein the computer program, when executed by a processor, implements the method for identifying a natural gas source of the present invention.

[0171] In a specific embodiment, in the Penglai area of ​​the Sichuan Basin, a drilling well is designed for the Dengying Formation, and a real-time gas source comparison analysis is required for the gas source during the drilling process. In this embodiment, the method for identifying the natural gas source of the present invention is used to identify the gas source, which specifically includes the following steps:

[0172] (1) Establish a database of drilling areas for marine strata in Penglai area of ​​Sichuan Basin

[0173] Collect natural gas data from conventional reservoirs with clear sources in the study area: Dengying Formation; source rock data of its potential sources: Doushantuo Formation (Layer 3), Qiongzhusi Formation / Niutitang Formation (Layer 2), Longmaxi Formation (Layer 1); retained gas data in source rocks: Doushantuo Formation, Qiongzhusi Formation / Niutitang Formation, Longmaxi Formation.

[0174] The natural gas data include natural gas composition, carbon and hydrogen isotopes of natural gas methane, ethane and propane, thermal maturity (Ro) of organic matter in source rocks, type of organic matter in source rocks, carbon isotope δ 13 C org , retained gas components and retained gas isotope δ 13 C 1 sourcerock , δ 13 C 2 sourcerock , δ 13 C 3 sourcerock ,δD 1 sourcerock ,δD 2 sourcerock Among them, the data of source rocks are shown in Table 1:

[0175] Table 1 Data of potential source rocks in the study area

[0176]

[0177] (2) Measuring the composition and isotope data of natural gas produced during drilling

[0178] In this embodiment, the drilling encounters the Cambrian Longwangmiao Formation (∈1l) stratum, accompanied by a large amount of gas invasion. The natural gas data in the drilling process is collected. The analytical instruments involved here include gas chromatographs, such as the GC-9160 model, which are used to analyze monomer hydrocarbons with a concentration higher than 0.0001% in natural gas; gas isotope mass spectrometers, such as the MAT271 model, are used to analyze gas components and isotope quantitative analysis, and the concentration of the detected natural gas components is higher than 0.0001%. The data obtained are shown in Table 2:

[0179] Table 2 Natural gas composition and isotope data of gas reservoirs encountered in typical wells in the study area

[0180] well name Depth(m) Horizon <![CDATA[CH4]]> <![CDATA[C2H6]]> <![CDATA[C3H8]]> <![CDATA[N2]]> <![CDATA[CO2]]> He <![CDATA[H2S]]> <![CDATA[δ 13 C1]]> <![CDATA[δD1]]> <![CDATA[δ 13 C2]]> <![CDATA[δD2]]> Well1 6972 <![CDATA[∈1l]]> 96.82 0.18 0.01 1.70 1.27 0.01 0.01 -38.2 -134 -36.4 / Well2 / <![CDATA[∈1l]]> 95.48 0.15 0.01 0.63 2.89 0.01 12.70 -34.7 -132 -34.3 /

[0181] (3) Analysis of the causes of natural gas encountered during drilling

[0182] The natural gas type identification mathematical model shown in equations (1)-(21) was used to analyze the genesis of the natural gas encountered in drilling. The results are as follows: Figure 2-7 As shown. Figure 2-7 It can be seen that the natural gas encountered during drilling in this embodiment is in the oil-type gas interval, and the natural gas is determined to be oil-type gas.

[0183] (4) Maturity analysis of natural gas encountered during drilling

[0184] The natural gas maturity is calculated using formula (22) to obtain the maturity of the drilled natural gas. The results for Well1 and Well2 are 1.88 and 2.99, respectively.

[0185] (5) Comparison of gas sources for natural gas encountered during drilling

[0186] First, the natural gas type is compared with the organic matter type of the source rock. In this example, the natural gas encountered is oil-type gas, and the potential source rocks include: Doushantuo Formation, Qiongzhusi Formation and Longmaxi Formation, and the organic matter types in the corresponding source rocks are Type I-Type II1, and these three sets of source rocks all meet the requirements.

[0187] Secondly, the natural gas maturity is compared with the thermal maturity of the organic matter in the source rock. The value of Well1 is close to Layer1 and Layer2, but far from Layer3; Well2 is closest to Layer2, followed by Layer1 and Layer3. Therefore, it is believed that Well1 may come from Layer1 and Layer2; and Well2 may come from Layer2.

[0188] Again, the ethane carbon isotope is compared with the organic carbon isotope of the source rock. The calculation is performed using formula (25). The results show that the potential Layer1 values ​​are 6.2 and 4.1 in Well1 and Well2, respectively, the Layer2 values ​​are 1.72 and 0.38 in Well1 and Well2, respectively, and the Layer3 values ​​are 6.58 and 4.48 in Well1 and Well2, respectively. Therefore, Layer2 is considered to be the gas source layer of Well1 and Well2.

[0189] Then, the natural gas components were compared with the retained gas components. The calculation was performed using formula (26). The results showed that the values ​​of Layer1 were 1.184 and 3.874 in Well1 and Well2, respectively, and the values ​​of Layer2 were 0.45 and 2.07 in Well1 and Well2, respectively. Due to the lack of relevant data for Layer3 in the database, no relevant calculation was performed.

[0190] Then, the natural gas isotopes were compared with the retained gas isotopes. The calculation was performed using formula (27). The results showed that the values ​​of Layer1 were 3.2 and 1.1 in Well1 and Well2, respectively, the values ​​of Layer2 were 1.58 and 0.52 in Well1 and Well2, respectively, and the values ​​of Layer3 were 4.2 and 2.1 in Well1 and Well2, respectively. Therefore, Layer2 is considered to be the gas source layer of Well1 and Well2.

[0191] Finally, based on the comprehensive judgment from the above five perspectives, it is believed that the natural gas in Well1 and Well2 both comes from Layer2.

[0192] In the above embodiment, the method for identifying the source of natural gas of the present invention can reduce the analysis time from 1 to 7 days in the prior art to 10 to 60 minutes, and the analysis efficiency is significantly improved. In this embodiment, when analyzing the origin of natural gas, a mathematical model for identifying the type of natural gas is used, which can achieve consistency in the output of each map without deformation of the map.

[0193] In summary, the present invention can identify the natural gas source more quickly and accurately. Compared with the prior art, the present invention has significant progress.

[0194] The above description is only a preferred embodiment of the present invention and does not constitute any form of limitation to the present invention. Although the present invention has been disclosed as a preferred embodiment as above, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention still falls within the scope of the technical solution of the present invention.

Claims

1. A method for identifying a natural gas source, characterized in that: The following steps are involved: S1: Collect natural gas data with clear sources and corresponding source rock data in the study area, and use them to establish a database for the study area; The natural gas data includes natural gas components and natural gas isotopes, and the natural gas isotopes include methane carbon isotopes, ethane carbon isotopes, propane carbon isotopes, methane hydrogen isotopes, and ethane hydrogen isotopes; The source rock data include source rock organic matter thermal maturity, source rock organic matter type, source rock organic carbon isotope, retained gas component and retained gas isotope, and the retained gas isotope is the same as the isotope included in the natural gas isotope; S2: collecting natural gas data of the natural gas to be identified in the study area, and performing natural gas genesis analysis based on the natural gas data of the natural gas to be identified to obtain the natural gas type of the natural gas to be identified; S3: calculating the natural gas maturity of the natural gas to be identified according to the natural gas type of the natural gas to be identified; S4: comparing the natural gas type of the natural gas to be identified with the organic matter type of the source rock in the database; comparing the natural gas maturity of the natural gas to be identified with the thermal maturity of the organic matter in the source rock in the database; If the comparison results of the two only show one corresponding source rock, then the source rock is the gas source of the natural gas to be identified; Otherwise, go to step S5; S5: comparing the ethane carbon isotope of the natural gas to be identified with the organic carbon isotope of the source rock in the database; comparing the natural gas components of the natural gas to be identified with the retained gas components in the database; comparing the natural gas isotopes of the natural gas to be identified with the retained gas isotopes in the database; S6: Obtaining the gas source of the natural gas to be identified according to the comparison results of step S4 and step S5; According to the comparison results of step S4 and step S5, when the gas source of the natural gas to be identified is obtained, a weight is assigned to each comparison result, and the weight of the result of the comparison between ethane carbon isotope and source rock organic carbon isotope, the weight of the result of the comparison between natural gas and retained gas, the weight of the result of the comparison between natural type and source rock organic matter type, and the weight of the result of the comparison between natural gas maturity and source rock organic matter thermal maturity decreases in sequence.

2. The method for identifying a natural gas source according to claim 1, characterized in that: In step S2, a natural gas type identification mathematical model is used to perform natural gas genesis analysis.

3. The method for identifying a natural gas source according to claim 2, characterized in that: The natural gas type identification mathematical model includes: (1)δ 13 Mathematical model for identifying natural gas types based on C1-δD1 Let x = δ 13 C1, represents the carbon isotope of methane; y = δD1, represents the hydrogen isotope of methane; the δ 13 The mathematical model for natural gas type identification based on C1-δD1 is: Where: Ω1(x, y) is the marine sapropelic area; Ω2(x, y) is the coal-bearing source rock area; (2)δ 13 Mathematical model for identifying natural gas types based on C2-δD1 Let x = δ 13 C2, represents ethane carbon isotope; y = δD1; the δ 13 The mathematical model for natural gas type identification of C2-δD1 is: (3)δ 13 C1-δ 13 Mathematical model for identifying natural gas types based on C2 Let x = δ 13 C1;y=δ 13 C2; said δ 13 C1-δ 13 The mathematical model for natural gas type identification of C2 is: Ω3(x,y)={(x,y)|-28≤y≤-24,xy≤0} (5) Ω4(x,y)={(x,y)|-30≤y≤-28,xy≤0} (6) Ω5(x,y)={(x,y)|-36≤y≤-30,xy≤0} (7) Where: Ω3(x,y) is the coal-type gas area; Ω4(x,y) is the mixed gas area; Ω5(x,y) is the oil-type gas area; (4) Mathematical model for distinguishing kerogen degradation gas and crude oil cracking gas based on ln(C1 / C2)-ln(C2 / C3) Assume x=ln(C1 / C2), where C1 represents the methane content and C2 represents the ethane content; y=ln(C2 / C3), where C3 represents the propane content; the mathematical model for distinguishing kerogen degradation gas and crude oil cracking gas of ln(C1 / C2)-ln(C2 / C3) is: f1(x,y)=160.1·sin(0.0057x-0.0021)+0.877·sin(1.139x+2.498)-y (8) When f1(x,y)>0 and f2(x,y)<0, it is kerogen degradation gas; when f2(x,y≥0, it is crude oil cracking gas; (5)δ 13 C1-C1 / C 2+3 Mathematical model for natural gas type identification Let x = δ 13 C1;y=C1 / C 2+3 , where C 2+3 Indicates the content of ethane and propane; the δ 13 C1-C1 / C 2+3 The mathematical model for natural gas type identification is: Ω6(x,y)={(x,y)|350≤y≤100000,-100≤x≤-52,xy+49.67y+1867≤0} (10) Where: Ω6(x,y) is the biogenic gas area; Ω7(x,y) is the thermogenic gas area; (6)δ 13 C2-δ 13 Mathematical model for identifying natural gas types based on C1 Let x = δ 13 C2;y=δ 13 C1; the δ 13 C2-δ 13 The mathematical model for natural gas type identification of C1 is: Ω 11 (x,y)={(x,y)|-29≤x≤-28,-44≤y≤-30} (15) Ω 12 (x,y)={(x,y)|-50≤x≤-15,-55≤y≤-15,9.29x-y≤3.07}-Ω 10 (x,y) (16) Where: Ω8(x,y) is region I; Ω9(x,y) is region II; Ω 10 (x, y) is region III; Ω 11 (x, y) is the IV region; Ω 12 (x,y) is a blank area; (7)δ 13 C3-δ 13 Mathematical model for identifying natural gas types based on C1 Let x = δ 13 C3, represents propane carbon isotope; y = δ 13 C1; the δ 13 C3-δ 13 The mathematical model for natural gas type identification of C1 is: Ω 11 (x,y)={(x,y)|-29≤x≤-28,-44≤y≤-30} (20) Ω 12 (x,y)={(x,y)|-40≤x≤-15,-55≤y≤-15,9.29x-y≤3.07}-Ω 10 (x,y)(21)。 4. The method for identifying a natural gas source according to claim 1, characterized in that: In step S3, when the natural gas to be identified is oil-type gas, the maturity of the natural gas is calculated using the following formula: δ 13 C1≈15.80lgRo naturalgas -42.20 (22) When the natural gas to be identified is coal-type gas, the natural gas maturity is calculated using the following formula: δ 13 C1≈14.12lgRo naturalgas -34.39 (23) Where: 13 C1 represents the carbon isotope of methane; Ro naturalgas Indicates the maturity of natural gas.

5. The method for identifying a natural gas source according to claim 1, characterized in that: In step S4 and step S5, when performing the comparison, similarity calculation or pattern matching method is used to perform comparative analysis.

6. The method for identifying a natural gas source according to claim 5, characterized in that: In step S4, when the natural gas type of the natural gas to be identified is compared with the organic matter type of the source rock in the database, type I and type II1 in the source rock correspond to oil-type gas in the natural gas; type II2 in the source rock corresponds to oil-type gas-coal-type gas in the natural gas; type III in the source rock corresponds to coal-type gas in the natural gas.

7. The method for identifying a natural gas source according to claim 5, characterized in that: In step S4, when the natural gas maturity of the natural gas to be identified is compared with the thermal maturity of the organic matter in the source rock in the database, the following formula is used for identification: Where: Layers represents potential source rock; i represents potential source rock layer; M represents the total number of potential source rock layers; N represents the total number of source rock Ro data in the i-th layer; represents the jth Ro data in the i-th source rock layer; Ro naturalgas Indicates the maturity of the natural gas to be identified.

8. The method for identifying a natural gas source according to claim 7, characterized in that: In step S5, when comparing the ethane carbon isotope of the natural gas to be identified with the organic carbon isotope of the source rock in the database, the following formula is used for identification: Where: represents the organic carbon isotope of the jth sample in the i-th layer of source rock; Represents the carbon isotope of natural gas ethane to be identified.

9. The method for identifying a natural gas source according to claim 8, characterized in that: In step S5, when comparing the natural gas components of the natural gas to be identified with the retained gas components in the database, the following formula is used for identification: Where: Dc represents the dryness coefficient of the jth natural gas data in the i-th source rock layer; naturalgas It indicates the dryness factor of natural gas, i.e. the ratio of methane / methane and its higher alkanes; represents the N2 content of the jth natural gas data in the i-th source rock layer; N 2naturalgas Indicates the N2 content in the natural gas to be identified; represents the CO2 content of the jth natural gas data in the i-th source rock layer; CO 2naturalgas Indicates the CO2 content in the natural gas to be identified; represents the He content of the jth natural gas data in the i-th source rock layer; He naturalgas Indicates the He content in the natural gas to be identified; represents the H2 content of the jth natural gas data in the i-th layer of source rock; H 2naturalgas Indicates the H2 content in the natural gas to be identified; When comparing the natural gas isotopes of the natural gas to be identified with the isotopes of the retained gas in the database, the following formula is used for identification: Where: represents the jth natural gas data in the i-th source rock layer value; Indicates the natural gas to be identified

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