Method for quantitatively evaluating high-heat-evolution mixed-source natural gas mixing ratio

Abstract

The present application relates to a kind of quantitative evaluation high heat evolution mixed source natural gas mixing ratio method, belong to oil and gas exploration and development technical field.The method of the present application includes the following steps: according to formula I, the difference of each natural gas sample ethane carbon isotope composition relative to methane in target zone target layer position high heat evolution continental mixed source gas reservoir is calculated Characteristic parameter T, and according to formula I, the oil type gas end member value T 油 And coal type gas end member value T 煤 ;Based on end member value T 煤 And T 油 , the linear relationship between oil type gas mixing ratio and mixed source gas characteristic parameter is established, and the oil type gas mixing ratio of each natural gas sample is calculated, and the average value is used as the mixing ratio of oil type gas in mixed source gas reservoir;And / or the linear relationship between coal type gas mixing ratio and mixed source gas characteristic parameter is established, and the coal type gas mixing ratio of each natural gas sample is calculated, and the average value is used as the mixing ratio of coal type gas in mixed source gas reservoir.The method of the present application can quantitatively calculate the mixing ratio of continental coal type gas and / or marine oil type gas in high heat evolution continental mixed source gas reservoir.

Description

TECHNICAL FIELD

[0001] The present application relates to a method for quantitatively evaluating the mixing ratio of high-thermal-evolution mixed-source natural gas, and belongs to the technical field of oil and gas exploration and development. BACKGROUND

[0002] Natural gas, as a low-carbon fossil energy, is an important carrier for energy structure transformation. At present, the main positions of natural gas exploration and development in China are located in the three large cratonic basins of Sichuan, Tarim and Ordos. The cumulative proven natural gas geological reserves of each basin are all more than 2×10 12 m 3 , and the annual gas production is all more than 300×10 8 m 3 . With theoretical innovation and technological breakthrough, the exploration and development targets of natural gas have marched from middle-shallow layer to deep layer, from structural gas reservoir to lithologic gas reservoir and composite gas reservoir, from single carbonate gas reservoir to conventional clastic rock gas reservoir, low-permeability tight gas reservoir, and shale gas reservoir and other types of gas reservoirs, thereby presenting a multi-field and multi-layered three-dimensional exploration scene of marine and terrestrial facies in parallel, and conventional and unconventional in parallel.

[0003] Through complex geological processes, fluid migration or energy conversion may occur between different types of gas reservoirs, thus forming some genetic relationship. During geological history, deep gas usually migrates to shallow parts, marine gas migrates to continental strata, and shale gas migrates to conventional gas reservoirs, leading to the mixing of natural gas of different properties and the formation of mixed gas reservoirs. Especially in the uplifted areas of the orogenic belt front of the sedimentary basin, different period, scale and stress characteristics of fault systems are usually developed, which creates conditions for the long-distance transfer of energy and fluid. For example, the continental tight clastic gas reservoirs in the orogenic belt front of Sichuan Basin have the characteristics of “dual-source hydrocarbon supply of marine and continental facies”, which is manifested as the mixed gas of underlying high thermal evolution marine oil-type gas and self-derived coal-type gas. The ethane carbon isotope value of the continental coal-type gas is generally not less than-28‰, and is higher than the carbon isotope value of methane, showing normal carbon isotope sequence. The ethane carbon isotope value of the marine oil-type gas is generally lower than-28‰, and often shows the characteristics of reversed methane and ethane carbon isotope (excluding natural gas obviously affected by secondary alteration such as thermal chemical sulfate reduction). The mixing of the two leads to the reversal of methane and ethane carbon isotope composition in continental tight clastic gas reservoirs to different degrees. The identification of mixed gas sources and mixing ratio is a prerequisite for the study of natural gas reservoir accumulation and evolution process and main controlling factors, and has important guiding significance for the evaluation of exploration targets and well deployment. Through quantitative calculation of the mixing ratio of different source natural gas in mixed gas reservoirs, the main hydrocarbon source rock is determined, and combined with other reservoir conditions analysis, the favorable target is optimized, which will greatly improve the exploration success rate. If the main hydrocarbon source rock of the mixed gas reservoir is misjudged, it will lead to the failure of well deployment, and then cause a lot of waste of manpower and material resources.

[0004] With the deepening of exploration, the exploration object is gradually complex, and it is increasingly difficult to find gas reservoirs with single source. The mixed source gas reservoirs with complex gas sources and high thermal evolution degree gradually become the main body of new discoveries. The chemical composition of high thermal evolution mixed source gas is relatively simple, with methane and ethane as the main alkane gas components, and the content of propane and butane is extremely low. The carbon isotope composition of methane and ethane usually presents reverse characteristics. Since the mixed source gas reflects the geochemical characteristics of natural gas from multiple sources, the contribution of each type of hydrocarbon source rock or the proportion of each source gas cannot be effectively determined by using its own geochemical parameters. Moreover, unlike crude oil, it is difficult to detect biomarker compounds that can be used for hydrocarbon source identification in high thermal evolution mixed source gas, and the calculation method of mixing ratio is limited. In recent years, some scholars have tried to calculate the mixing ratio of mixed source gas by using the carbon isotope composition of methane and the characteristics of light hydrocarbons, and have achieved certain results, but there are still the following three problems: (1) The established mixing ratio identification chart is relatively complex, and the effect of actual application is not good; (2) The content of light hydrocarbon components above C4 in high thermal evolution mixed source gas is extremely low, and enrichment treatment is required, but the requirements for instrument devices and experimental techniques are high, and it is difficult to promote rapidly; (3) The parent hydrocarbon source rock of marine oil-type gas in high thermal evolution mixed source gas has entered the high and over-mature stage, and the carbon isotope value of methane is close to or higher than that of overlying terrestrial coal-type gas, and the carbon isotope composition of methane cannot be effectively used for mixing ratio calculation. In summary, the current technical means cannot be well applied to the mixed gas reservoir of high thermal evolution marine oil-type gas and terrestrial coal-type gas. How to quickly and effectively quantitatively evaluate the mixing ratio of high thermal evolution mixed source gas is one of the key problems in current natural gas exploration. SUMMARY

[0005] The purpose of the present application is to provide a method for quantitatively evaluating the mixing ratio of high thermal evolution mixed source gas, which can quickly and effectively calculate the mixing ratio of high thermal evolution mixed source gas reservoir of marine oil-type gas and terrestrial coal-type gas.

[0006] In order to achieve the above purpose, the technical scheme adopted by the present application is:

[0007] A method for quantitatively evaluating the mixing ratio of high thermal evolution mixed source gas, comprising the following steps:

[0008] 1) Obtain the content and carbon isotope value of each alkane gas component in each natural gas sample of the target layer high thermal evolution terrestrial gas reservoir in the target area, and then calculate the differential characteristic parameter T of the ethane carbon isotope composition of each natural gas sample of the target area high thermal evolution terrestrial gas reservoir relative to methane according to formula I; the high thermal evolution terrestrial gas reservoir of the target layer in the target area is a mixed gas reservoir of high thermal evolution marine oil-type gas and terrestrial coal-type gas;

[0009]

[0010] In formula I, T is a parameter reflecting the differential characteristics of the ethane carbon isotope composition of the natural gas sample relative to methane;

[0011] ω C2H6 is the percentage content of ethane in the natural gas sample, %;

[0012] is the sum of the percentage contents of methane, ethane, propane and butane in the natural gas sample, %;

[0013] δ 13 C1 is the methane carbon isotope value of the natural gas sample, ‰;

[0014] δ 13 C2 is the ethane carbon isotope value of the natural gas sample, ‰;

[0015] 2) Obtain the content and carbon isotope value of each alkane gas component of a coal-type gas sample exhibiting a methane and ethane positive carbon isotope sequence in a same-layer continental gas reservoir with a single humic source rock in the adjacent area of the target area, and determine the end-member value T of the coal-type gas characteristic parameter according to formula I 煤 ;

[0016] Obtain the content and carbon isotope value of each alkane gas component of an oil-type gas sample exhibiting a methane and ethane negative carbon isotope sequence in a underlying marine gas reservoir with a single sapropelic source rock in the target area and / or the adjacent area of the target area, and determine the end-member value T of the oil-type gas characteristic parameter according to formula I 油 ;

[0017] 3) Based on the end-member value T 煤 of the coal-type gas characteristic parameter and the end-member value T 油 of the oil-type gas characteristic parameter obtained in step 2), establish a linear relationship between the oil-type gas mixing ratio and the mixed-source gas characteristic parameter:

[0018] H 油 = (T 混 -T 煤 ) / (T 油 -T 煤 )×100% (II);

[0019] In formula (II) and (III), H 油 represents the oil-type gas mixing ratio in the mixed-source gas, %;

[0020] H 煤 represents the coal-type gas mixing ratio in the mixed-source gas, %;

[0021] T 油 represents the end-member value of the oil-type gas characteristic parameter;

[0022] T 煤 represents the end-member value of the coal-type gas characteristic parameter;

[0023] T 混 representing the characteristic parameter of the mixed-source gas;

[0024] After the linear relationship between the oil-type gas mixing ratio and the characteristic parameter of the mixed-source gas is established, the oil-type gas mixing ratio of each natural gas sample of the high-thermal-evolution continental mixed-source gas reservoir in the target area is calculated according to the characteristic parameter T value of each natural gas sample of the high-thermal-evolution continental mixed-source gas reservoir in the target area determined in step 1) and the linear relationship between the oil-type gas mixing ratio and the characteristic parameter of the mixed-source gas, and the average value of the oil-type gas mixing ratios of all mixed-source natural gas samples is taken as the oil-type gas mixing ratio of the high-thermal-evolution continental mixed-source gas reservoir.

[0025] and / or the endmember value T 煤 of the oil-type gas characteristic parameter obtained in step 2) is taken as the oil-type gas mixing ratio of the high-thermal-evolution continental mixed-source gas reservoir. 油 The linear relationship between the oil-type gas mixing ratio and the characteristic parameter of the mixed-source gas is established:

[0026] H 煤 = (T 油 -T 混 ) / (T 油 -T 煤 )×100% (III).

[0027] In formula (III), H 煤 represents the oil-type gas mixing ratio in the mixed-source gas, %.

[0028] T 油 represents the endmember value of the oil-type gas characteristic parameter.

[0029] T 煤 represents the endmember value of the oil-type gas characteristic parameter.

[0030] T 混 represents the endmember value of the oil-type gas characteristic parameter.

[0031] After the linear relationship between the oil-type gas mixing ratio and the characteristic parameter of the mixed-source gas is established, the oil-type gas mixing ratio of each natural gas sample of the high-thermal-evolution continental mixed-source gas reservoir in the target area is calculated according to the characteristic parameter T value of each natural gas sample of the high-thermal-evolution continental mixed-source gas reservoir in the target area determined in step 1) and the linear relationship between the oil-type gas mixing ratio and the characteristic parameter of the mixed-source gas, and the average value of the oil-type gas mixing ratios of all mixed-source natural gas samples is taken as the oil-type gas mixing ratio of the high-thermal-evolution continental mixed-source gas reservoir.

[0032] The method for quantitatively evaluating the mixing ratio of the high-thermal evolution mixed-source natural gas mixture according to the application takes the product of the proportion of ethane in alkane gas components and the difference between the carbon isotopes of ethane and methane as a new type of characteristic parameter, quantitatively calculates the mixing ratio of the land-source coal-type gas and / or the marine-source oil-type gas of the high-thermal evolution land mixed-source gas reservoir, can overcome the problem that the prior art cannot accurately evaluate the proportion of each type of natural gas in the high-thermal evolution land mixed-source gas reservoir, and is helpful to further clarify the genesis and source of the natural gas in the orogenic belt front dense clastic rock mixed-source gas reservoir, and provides technical support for well site demonstration and deployment of the orogenic belt front dense clastic rock mixed-source gas reservoir.

[0033] According to formula I, the T value of each natural gas sample of the target area high-thermal evolution mixed-source gas reservoir is calculated, if the T value is negative, it indicates that the sample is obviously affected by the marine-source oil-type gas, and if the T value is positive, it indicates that the sample is obviously affected by the land-source coal-type gas.

[0034] The methane carbon isotope composition of natural gas is obviously affected by the thermal evolution degree of the parent material, and with the increase of the thermal evolution degree of the parent material, the carbon isotope composition of the generated methane gradually becomes heavy. Under the condition of the same thermal evolution degree, the methane carbon isotope value of the oil-type gas generated by sapropel-type organic matter is lower than that of the coal-type gas generated by humus-type organic matter. Compared with the land clastic rock series, the marine carbonate rock series in China has the characteristics of early formation time, large burial depth and high thermal evolution degree. Due to the extremely high thermal maturity of sapropel-type organic matter in the marine series, the methane carbon isotope composition of the oil-type gas generated by the sapropel-type organic matter is obviously heavy, and is close to or even heavier than the methane generated by the humus-type organic matter in the overlying land series with low thermal maturity, resulting in that the methane carbon isotope value of the high-thermal evolution marine oil-type gas is similar to that of the overlying land coal-type gas.

[0035] The difference between the two types of natural gas in terms of geochemical characteristics mainly lies in the proportion of ethane in alkane gas components and the difference between the carbon isotopes of ethane and methane. Due to the extremely high thermal evolution degree of the sapropel-type organic matter in the underlying marine series, the natural gas generated by the sapropel-type organic matter is typical dry gas, the alkane gas components are mainly methane, followed by ethane, and the contents of propane and butane are usually lower than the detection limit. The thermal maturity of the humus-type organic matter in the overlying land series is relatively low, the content of heavy hydrocarbon gas components in the generated natural gas is relatively high, and thus the proportion of ethane in the alkane gas components of the underlying marine oil-type gas is lower than that of the overlying land coal-type gas. The methane and ethane carbon isotope compositions of the deep marine series oil-type gas usually show reverse characteristics (not including the natural gas obviously affected by secondary alteration such as thermal chemical sulfate reduction), and the main reason is that the sapropel-type organic matter is at the high and over-maturity stage, a large amount of liquid hydrocarbon generated in the early stage is further cracked under high temperature conditions to generate ethane rich in 12 C, and the ethane rich in 13C The mixing of the natural gas causes the carbon isotope value of ethane in the natural gas to decrease significantly, even lower than that of methane, and further forms carbon isotope inversion phenomenon. The methane carbon isotope composition of the coal-type gas in the terrestrial layer series is generally lighter than that of ethane, and presents normal carbon isotope sequence. The main reason is that the content of the condensate or light hydrocarbon generated by the humic organic matter is less, and the thermal evolution degree of the terrestrial layer series is lower, which leads to the coal-derived condensate and light hydrocarbon cracking to generate the rich hydrogen and carbon isotope of methane. Therefore, the carbon isotope of ethane in the coal-type gas is not significantly lower than that of methane, and the carbon isotope sequence of the coal-type gas is normal. 12 C Ethane is not enough to cause the carbon isotope inversion of methane and ethane in the coal-type gas.

[0036] In summary, the methane carbon isotope composition of the marine oil-type gas and the terrestrial coal-type gas is relatively similar, and the parameter cannot effectively distinguish the two types of natural gas. However, the proportion of ethane in the alkane gas component of the marine oil-type gas is relatively low, and the carbon isotope difference between ethane and methane is negative; the proportion of ethane in the alkane gas component of the terrestrial coal-type gas is relatively high, and the carbon isotope difference between ethane and methane is positive. The product of the proportion of ethane in the alkane gas component and the carbon isotope difference between ethane and methane generally reflects the differential characteristics of the carbon isotope composition of ethane relative to methane in each type of natural gas. In the process of mixing the two types of natural gas, as a characteristic parameter, it and the mixing ratio jointly affect the carbon isotope composition of the alkane gas component in the mixed-source gas. Therefore, by using the key parameter, the mixing ratio of the marine oil-type gas and the terrestrial coal-type gas in the high-thermal-evolution mixed-source gas can be quickly and effectively calculated.

[0037] Further, in step 1), any two samples of the natural gas samples of the target layer of the target area of the high-thermal-evolution terrestrial gas reservoir in the target layer are natural gas samples of different wells or natural gas samples of different depths of the same well. If there are multiple test results of the natural gas samples of the same depth of the same well, the average value of all test results of each parameter is taken as the representative value of the corresponding parameter of the natural gas sample of the well at the depth.

[0038] Further, in step 2), the characteristic parameter T value of each coal-type gas sample of the same layer terrestrial gas reservoir with single humic-type source rock hydrocarbon supply is calculated according to formula I, and then the average value of the characteristic parameter T values of all coal-type gas samples is taken as the end-member value T of the coal-type gas characteristic parameter. 煤 .

[0039] Further, in step 2), the characteristic parameter T value of each oil-type gas sample of the underlying marine gas reservoir with single sapropelic-type source rock hydrocarbon supply is calculated according to formula I, and then the average value of the characteristic parameter T values of all oil-type gas samples is taken as the end-member value T of the oil-type gas characteristic parameter. 油 . BRIEF DESCRIPTION OF DRAWINGS

[0040] Figure 1 A flowchart of the method for quantitatively evaluating the mixing ratio of the high-thermal-evolution mixed-source natural gas of the embodiments;

[0041] Figure 2The figure of the correlation between the mixing ratio of the high thermal evolution mixed-source gas reservoir in the examples and the characteristic parameters. DETAILED DESCRIPTION

[0042] The following will further illustrate the technical solutions of the present application by taking a terrestrial clastic rock gas reservoir in an alpha horizon of a block A in a certain orogenic belt front uplift area as an example. The terrestrial clastic rock gas reservoir in the alpha horizon of the block A is a mixed gas reservoir of high thermal evolution marine oil-type gas and terrestrial coal-type gas, and part of the natural gas samples show methane and ethane carbon isotope reversal. The natural gas of marine carbonate rock gas reservoirs in beta and gamma horizons underlying the alpha horizon of the block A is oil-type gas showing methane and ethane carbon isotope reversal, and has the characteristic of single sapropelic source rock hydrocarbon supply. The block B is adjacent to the block A, and the natural gas of the terrestrial clastic rock gas reservoir in the alpha horizon of the block B is coal-type gas showing methane and ethane normal carbon isotope sequence, and has the characteristic of single humic source rock hydrocarbon supply. The block C is adjacent to the block A, and the natural gas of marine carbonate rock gas reservoirs in gamma and delta horizons of the block C is oil-type gas showing methane and ethane carbon isotope reversal, and has the characteristic of single sapropelic source rock hydrocarbon supply.

[0043] Example 1

[0044] The method for quantitatively evaluating the mixing ratio of the high thermal evolution mixed-source natural gas in the present example has a flow as shown in the figure, and includes the following steps: Figure 1

[0045] 1) Obtain the alkane gas component content and carbon isotope value of each natural gas sample of the terrestrial clastic rock gas reservoir in the alpha horizon of the block A, as shown in Table 1. Any two samples in all natural gas samples are natural gas samples of different wells or different depths of the same well. When obtaining the alkane gas component content and carbon isotope value of each natural gas sample, for the natural gas sample of the same well and the same depth, if there are multiple test results, the average value of all test results of each parameter is taken as the representative value of the corresponding parameter of the natural gas sample of the well and the depth.

[0046] From the data in Table 1, the methane and ethane carbon isotope values of the natural gas sample A3 of the terrestrial clastic rock gas reservoir in the alpha horizon of the block A are-30.6 ‰ and-34.3 ‰, respectively, showing a typical methane and ethane negative carbon isotope sequence characteristic. Since the natural gas sample with the methane and ethane negative carbon isotope sequence characteristic can be used as one of the evidences for determining that the high thermal evolution terrestrial gas reservoir is a mixed gas reservoir of marine oil-type gas and terrestrial coal-type gas, it can be known from the data in Table 1 that the terrestrial clastic rock gas reservoir in the alpha horizon of the block A is a mixed gas reservoir of high thermal evolution marine oil-type gas and terrestrial coal-type gas (i.e., a high thermal evolution mixed-source gas reservoir in the alpha horizon of the block A).

[0047] Table 1 Geochemical characteristics and T values of marine and terrestrial natural gas samples in the block A and adjacent areas

[0048] ​

[0049]

[0050] Note: " / " means undetected or no data obtained.

[0051] According to Formula I, the proportion of ethane in alkane gas components and the difference between carbon isotopes of ethane and methane of the high-thermal evolution mixed-source gas reservoir sample in the A block alpha horizon are used to calculate the size of the new characteristic parameter T of each sample (samples A1-A8) in the A block, and the results are shown in Table 1. The calculation results in Table 1 show that the T value of the natural gas sample collected from the anticline belt in the A block is between -3.86 and -0.60, indicating that it is obviously affected by marine-derived oil-type gas; and the T value of the natural gas sample collected from the sag belt is between 0.03 and 0.76, indicating that these samples mainly show the characteristics of terrestrial-derived coal-type gas.

[0052] 2) Obtain the component and carbon isotope data of the coal-type gas sample (samples B1-B11; Table 1) showing the sequence of methane and ethane in the alpha horizon gas reservoir with single humic source rock in the B block (adjacent area of the A block). According to Formula I, the proportion of ethane in alkane gas components and the difference between carbon isotopes of ethane and methane of the above natural gas sample are used to calculate the T value of each sample, and the results are shown in Table 1. The results show that the T value of samples B1-B11 is between 4.68 and 41.10 (Table 1), with an average of 13.04. Therefore, 13.04 is selected as the end member value T 煤 of the coal-type gas characteristic parameter.

[0053] 3) Obtain the content and carbon isotope value of each alkane gas component of the oil-type gas sample (samples A9-A10, C1-C3; Table 1) showing the sequence of methane and ethane in the underlying marine gas reservoir with single sapropelic source rock in the A block and the C block (adjacent area of the A block), and calculate the T value of each sample according to Formula I, and the results are shown in Table 1. As shown in Table 1, the T value of the above marine gas reservoir natural gas sample in the A block and the C block is between -24.09 and -0.09 (Table 1), with an average of -6.15, so it is taken as the end member value T 油 of the oil-type gas characteristic parameter.

[0054] 4) Based on the coal-type gas characteristic parameter end member value T 煤 set in step 2) and the oil-type gas characteristic parameter end member value T 油 set in step 3), the linear relationship between the mixing ratio of oil-type gas and coal-type gas and the mixed-source gas characteristic parameter is established according to Formulas II and III. As shown in Figure 2 , the linear relationship between the mixing ratio (H 油 ) of oil-type gas and the mixed-source gas characteristic parameter (T 混 ) is H 油 =-0.0521×T 混+0.6795, coal-type gas mixing ratio (H 煤 ) and the linear relationship of the characteristic parameter (T 混 ) of the mixed-source gas is H 煤 = 0.0521 x T 混 + 0.3205.

[0055] 5) According to the characteristic parameter T value of each natural gas sample of the high thermal evolution mixed-source gas reservoir in the α layer of the A block calculated in step 1) and the linear relationship of the oil-type gas and coal-type gas mixing ratio and the characteristic parameter of the mixed-source gas established in step 4), the mixing ratio of the oil-type gas and the coal-type gas in each sample is obtained, and the results are shown in Table 2.

[0056] Table 2 Calculation results of the mixing ratio of each mixed-source gas sample in the A block

[0057]

[0058] As can be seen from Table 2, the mixing ratio of the marine oil-type gas in the high thermal evolution mixed-source gas reservoir in the α layer of the A block is between 64.0% and 88.1%, and the mixing ratio of the terrestrial coal-type gas is between 11.9% and 36.0%. The average value of the oil-type gas and the coal-type gas mixing ratio of all samples in the A block is taken as the mixing ratio of the oil-type gas and the coal-type gas in the high thermal evolution mixed-source gas reservoir in the α layer of the A block, and it is calculated that the mixing ratio of the oil-type gas in the A block is 73.8%, and the mixing ratio of the coal-type gas is 26.2%.

[0059] In addition, according to Table 2, the distribution range of the mixing ratio of the mixed-source gas reservoir in the anticline zone and the depression zone can be determined, and the average value of the oil-type gas and the coal-type gas mixing ratio of each sample in the anticline zone and the depression zone is taken as the mixing ratio of the oil-type gas and the coal-type gas in the mixed-source gas reservoir of each structural zone. As shown in Table 2, the mixing ratio of the marine oil-type gas in the mixed-source gas reservoir in the α layer of the anticline zone of the A block is between 71.1% and 88.1%, with an average of 78.6%; the mixing ratio of the terrestrial coal-type gas is between 11.9% and 28.9%, with an average of 21.4%; the mixing ratio of the marine oil-type gas in the mixed-source gas reservoir in the α layer of the depression zone is between 64.0% and 67.8%, with an average of 65.8%; and the mixing ratio of the terrestrial coal-type gas is between 32.2% and 36.0%, with an average of 34.2%.

[0060] As can be seen from Table 1 and Table 2, the genesis and source of natural gas in the terrestrial clastic rock gas reservoir of the alpha horizon in the A block of the uplift area in the front of a certain orogenic belt are relatively complex, and the whole performance is a mixture of oil-type gas from underlying marine facies and coal-type gas from self source, and the marine oil-type gas is dominant, and the mixing ratio is more than half. Especially, the gas reservoir in the anticline belt is significantly affected by marine oil-type gas, and the mixing ratio of oil-type gas is close to 90%. But it is worth noting that from the anticline belt to the sag belt, the contribution of marine oil-type gas in the natural gas of the alpha horizon gas reservoir is significantly reduced, and the mixing ratio of terrestrial coal-type gas is significantly increased, and the highest is close to 40%, which implies that there may be a gas reservoir dominated by coal-type gas from self source in some areas of the sag belt. The accumulation process, distribution rule and productivity characteristics of such gas reservoirs should be different from those of the gas reservoirs dominated by marine oil-type gas in the anticline belt. At present, with the gradual transfer of exploration and deployment work in the A block from the anticline belt to the sag belt, it is urgent to study the relationship between the mixing ratio of mixed source gas reservoir and the geological characteristics and productivity characteristics of the gas reservoir, to determine the key parameters affecting the mixing ratio, and to carry out geological evaluation and well site deployment work for different types of gas reservoirs. The above results are consistent with the current geological understanding and exploration results, which confirms the applicability and correctness of the present application.

[0061] In summary, the method of the present application can quickly and effectively evaluate the mixing ratio of high thermal evolution mixed source gas reservoir, which makes up for the deficiency that the current technical method cannot be applied to high thermal evolution mixed source gas reservoir of marine oil-type gas and terrestrial coal-type gas, and helps to speed up the exploration pace of terrestrial clastic rock mixed source gas reservoir in the uplift area in the front of an orogenic belt, and provides good technical support and reliable reference basis for the selection of subsequent favorable exploration targets.

Claims

1. A method for quantitatively evaluating the mixing ratio of a high-thermal-evolution mixed-source natural gas, characterized by: The method comprises the following steps: 1) obtaining the content and carbon isotope value of each alkane gas component in each natural gas sample of the target layer high-thermal evolution continental gas reservoir in the target area, and then calculating the differential characteristic parameter T of ethane carbon isotope composition relative to methane of each natural gas sample of the target layer high-thermal evolution continental gas reservoir in the target area according to formula I; the target layer high-thermal evolution continental gas reservoir in the target area is a mixed gas reservoir of high-thermal evolution marine oil-type gas and continental coal-type gas; In formula (I), T is a parameter reflecting the differential characteristics of the ethane carbon isotope composition relative to methane of the natural gas sample; for the percentage content of ethane in the natural gas sample, %; is the sum of the percentage contents of methane, ethane, propane and butane in the natural gas sample, %; delta 13 C1 is the methane carbon isotope value of the natural gas sample, in ‰; delta 13 C2 is the ethane carbon isotope value of the natural gas sample, in ‰; 2) Obtain the content and carbon isotope value of each alkane gas component of the coal-type gas sample showing the methane, ethane normal carbon isotope sequence in the same layer gas reservoir with single humic source rock in the target area, and determine the end member value T of the coal-type gas characteristic parameter according to formula I 煤 ; The content and carbon isotope values of each alkane gas component of each oil-type gas sample showing a methane, ethane negative carbon isotope sequence in a underlying facies gas reservoir with a single sapropelic source rock for hydrocarbon supply in a target zone and / or adjacent zones of the target zone are obtained, and the end member value T of the oil-type gas characteristic parameter is determined according to formula I 油 ; 3) Based on the endmember value T of the coal-type gas characteristic parameter obtained in step 2) 煤 and the endmember value T of the oil-type gas characteristic parameter 油 , a linear relationship between the mixing ratio of the oil-type gas and the characteristic parameter of the mixed gas is established. H 油 = (T 混 -T 煤 ) / (T 油 -T 煤 ) x 100% (II); In formula (II) and (III), H 油 represents the mixing ratio of oil-type gas in mixed gas, % H 煤 indicates the mixing ratio of coal-type gas in mixed gas, % T 油 Endmember values representing oil-type gas characteristic parameters; T 煤 Endmember values representing the characteristic parameters of coal-type gas; T 混 representing a characteristic parameter of the mixed gas; After the linear relationship between the oil-type gas mixing ratio and the characteristic parameter of the mixed source gas is established, the oil-type gas mixing ratio of each natural gas sample of the high-thermal evolution continental mixed source gas reservoir is calculated according to the characteristic parameter T value of each natural gas sample of the high-thermal evolution continental mixed source gas reservoir in the target area determined in step 1) and the linear relationship between the oil-type gas mixing ratio and the characteristic parameter of the mixed source gas, and the average value of the oil-type gas mixing ratio of all mixed source natural gas samples is taken as the mixing ratio of the oil-type gas of the high-thermal evolution continental mixed source gas reservoir. and / or the endmember value T of the characteristic parameter of the coal-type gas obtained based on step 2) 煤 and the endmember value T of the characteristic parameter of the oil-type gas 油 , and a linear relationship between the mixing ratio of the coal-type gas and the characteristic parameter of the mixed gas is established. H 煤 = (T 油 -T 混 ) / (T 油 -T 煤 ) x 100% (III); In formula (III), H 煤 denotes the mixing ratio of coal-type gas in the mixed gas, %. T 油 Endmember values representing oil-type gas characteristic parameters; T 煤 Endmember values of characteristic parameters of coal-type gas T 混 representing a characteristic parameter of the mixed gas; After the linear relationship between the coal-type gas mixing ratio and the characteristic parameter of the mixed source gas is established, the coal-type gas mixing ratio of each natural gas sample of the high-thermal evolution continental mixed source gas reservoir is calculated according to the characteristic parameter T value of each natural gas sample of the high-thermal evolution continental mixed source gas reservoir in the target area determined in step 1) and the linear relationship between the coal-type gas mixing ratio and the characteristic parameter of the mixed source gas, and the average value of the coal-type gas mixing ratio of all mixed source natural gas samples is taken as the mixing ratio of the coal-type gas of the high-thermal evolution continental mixed source gas reservoir.

2. The method for quantitatively evaluating the mixing ratio of high-heat evolution mixed-source natural gas according to claim 1, characterized in that: In step 2), the characteristic parameter T value of each coal-type gas sample of the same layer gas reservoir with single humic source rock for hydrocarbon supply is calculated according to Formula I, and then the average value of the characteristic parameter T values of all coal-type gas samples is taken as the endmember value T of the coal-type gas characteristic parameter 煤 .

3. The method for quantitatively evaluating the mixing ratio of high-heat evolution mixed-source natural gas according to claim 1, characterized in that: In step 2), the characteristic parameter T value of each oil-type gas sample of the underlying facies gas reservoir with single sapropelic source rock for hydrocarbon supply is calculated according to Formula I, and then the average value of the characteristic parameter T values of all oil-type gas samples is taken as the endmember value T of the oil-type gas characteristic parameter 油 .

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