Quantitative characterization method for mixed source proportion of natural gas in petroliferous basin and maturity of thermogenic gas of natural gas

Abstract

The invention relates to a quantitative characterization method for the mixed source proportion of natural gas in a petroliferous basin and the maturity of thermogenic gas of the natural gas. The quantitative characterization method for the mixed source proportion of the natural gas comprises the following steps: determining natural gas causes and composition types of a petroliferous basin research area; analyzing whether the stratum of the research area of the petroliferous basin has a biogenic gas development condition or not; carrying out quantitative analysis on the judged mixed source area to obtain the proportion of the thermogenic gas to the biogenic gas in the natural gas; and quantitatively analyzing the maturity of the thermogenic gas in the natural gas. The natural gas is comprehensively judged, the mixed source proportion of the thermogenic gas and the biogas is quantitatively represented, meanwhile, interference of the biogenic gas on methane carbon isotope characteristics is avoided, the maturity of the thermogenic gas of the natural gas is accurately calculated, the reserves and distribution conditions of oil and gas resources are more comprehensively evaluated, and the method is suitable for popularization and application. And the exploration work is guided to be carried out in more potential areas and horizon.

Description

Technical Field

[0001] The present invention relates to the technical field of geological exploration and evaluation of oil and gas resources, and particularly relates to a method for quantitatively characterizing the mixed-source ratio of natural gas and the maturity of thermogenic gas in an oil and gas-bearing basin, and particularly relates to a method for quantitatively characterizing the mixed-source ratio of natural gas and the maturity of thermogenic gas in an offshore oil and gas-bearing basin. Background Art

[0002] Judging the origin and accumulation law of natural gas is of great significance for natural gas resource evaluation and natural gas exploration. However, compared with onshore areas, the number of drilled wells in offshore oil and gas-bearing basins is relatively small, and the source rocks are generally located deep in the basins, resulting in less source rock data obtained. Therefore, it is more difficult to study the origin and accumulation law of natural gas in offshore oil and gas-bearing basins. Currently, the widely used research method is to use the commonly used natural gas origin chart method in the industry to determine the origin of natural gas, and then calculate the maturity of thermogenic gas through the empirical formula (δ 13 C 1 –Ro) of methane carbon isotope and maturity, and comprehensively consider the maturity of the source rock series to finally determine the source of natural gas. However, this method is only applicable to the case of simple tectonic background, single source rock and no mixed source of natural gas. When there is complex tectonic evolution (such as tectonic inversion) and mixed source of thermogenic gas and biogenic gas, this method cannot obtain a more credible explanation for the origin of natural gas, and even may mislead the understanding of the accumulation and evolution of natural gas.

[0003] As the burial depth increases, the formation temperature continuously rises, and the source rock gradually transforms into oil and gas, showing obvious stage characteristics. In the shallow part of the basin, at a depth < 1500m and a temperature < 80°C, methanogens are active and biogas is generally developed; as the burial depth increases and the formation temperature increases, the activity of methanogens is inhibited, and a large amount of organic matter in the source rock is transformed into crude oil and thermogenic gas through thermal degradation. The typical characteristics of biogas are that methane dominates absolutely, lacking high-carbon number hydrocarbons such as ethane, propane and butane, and at the same time, the methane carbon isotope δ 13 C 1 is generally light (δ 13 C 1 < -50‰). According to the origin type, biogas can be divided into primary biogas (the material source is organic matter) and secondary biogas (the material source is the generated hydrocarbons); according to the thermal evolution stage, thermogenic gas can be divided into low-maturity gas, mature gas and high-maturity gas.

[0004] Many scholars have established empirical equations based on the carbon isotopes of natural gas and the measured Ro values ​​of its source rocks (reference: Cheng Xiong, Hou Dujie, Zhao Zhe, et al. Genesis and source analysis of natural gas in the Xihu Sag [J]. China Offshore Oil and Gas, 2019, 31(3): 50-60.), but they have not ruled out complex situations such as the mixed source of thermogenic gas and biogenic gas and secondary transformation of biodegradation, so the maturity of natural gas cannot be accurately obtained. For example, CN106249312A discloses a quantitative characterization method for the mixed source ratio of shallow gas in oil and gas basins. This method is only for shallow gas and does not take into account a series of complex evolutions that may occur during the migration and convergence of oil and gas, including mixed sources and biodegradation and other reservoir-forming effects.

[0005] Therefore, how to accurately determine the mixed source ratio of natural gas and the maturity of thermogenic gas in oil and gas basins is a technical problem that needs to be solved urgently in this field. Summary of the invention

[0006] In order to solve the above technical problems, the present invention provides a quantitative characterization method for the mixed source ratio of natural gas and the maturity of its thermogenic gas in oil and gas basins, which can deeply combine the natural gas accumulation evolution process, accurately identify thermogenic gas and biogenic gas and quantitatively characterize the mixed source ratio, and can accurately calculate the maturity of thermogenic gas in natural gas, effectively solving the problem of biogenic gas on the carbon isotope characteristic δ 13 C 1 interference.

[0007] To achieve this object, the present invention adopts the following technical solutions:

[0008] In a first aspect, the present invention provides a method for quantitatively characterizing the mixed source ratio of natural gas in an oil and gas basin.

[0009] The method for quantitatively characterizing the mixed source ratio of natural gas comprises the following steps:

[0010] (1) Determine the origin and composition of natural gas in the study area of ​​the petroliferous basin;

[0011] (2) Analyze whether the strata in the study area of ​​the oil and gas basin have the conditions for the development of biogenic gas;

[0012] (3) Quantitatively analyzing the mixed source area determined according to step (1) and step (2) to obtain the ratio of thermogenic gas to biogenic gas in the natural gas.

[0013] The present invention deeply combines the natural gas accumulation and evolution process. First, it determines the origin and composition type of natural gas in the research area of the oil and gas basin, then analyzes whether it has the conditions for the development of biogenic gas, accurately identifies thermogenic gas and biogenic gas, analyzes whether there are favorable conditions for the breeding of methanogens, determines the mixed source of natural gas in the research area of the oil and gas basin, and further determines the proportion of thermogenic gas and biogenic gas, so as to more comprehensively evaluate the reserves and distribution of oil and gas resources and guide the exploration work to more potential regions and horizons.

[0014] The present invention breaks the understanding of identifying the oil and gas in deeper buried strata as thermogenic gas. Especially for oil and gas basins with inversion structures, the strata that are deeply buried today may have been shallowly buried and at low temperatures in the geological history. When suitable water medium and organic matter nutrients and other conditions are available, the breeding of methanogens can also produce a mixed source phenomenon of thermogenic gas and biogenic gas.

[0015] Preferably, the determination of the origin and composition type of the natural gas in step (1) includes: determining the origin and composition type of the natural gas by analyzing the content of each component and the carbon isotope value of each component in the natural gas.

[0016] Preferably, the analysis of the content of each component and the carbon isotope value of each component in the natural gas includes: using a genetic diagram of natural gas formed by a relationship diagram with the carbon isotope value of methane in the natural gas as the abscissa and the carbon isotope value of carbon dioxide in the natural gas as the ordinate to determine the origin and composition type of the natural gas.

[0017] In step (1) of the present invention, it is further preferred to use a genetic diagram of natural gas formed by a relationship diagram with the carbon isotope value of methane in the natural gas as the abscissa and the carbon isotope value of carbon dioxide in the natural gas as the ordinate to determine the origin and composition type of the natural gas. The genetic diagram of natural gas is the one disclosed in the reference A.V. Milkov, G. Etiope, Revised genetic diagrams for natural gases based on a global dataset of >20,000 samples[J]. Organic Geochemistry, 125(2018):109 - 120. Figure 9 The genetic diagram of natural gas shown as C in it can more accurately distinguish thermogenic gas, biogenic gas and mixed - source gas compared with the diagram with the carbon isotope value of methane in the natural gas as the abscissa and the content of methane in the natural gas / (content of ethane + content of propane) as the ordinate, avoiding the phenomenon of directly misidentifying the deeper buried oil and gas reservoirs as thermogenic gas.

[0018] Preferably, step (1) further includes analyzing the trend of the carbon isotope values of the components in the natural gas with the change of depth in the study area of the oil and gas bearing basin.

[0019] The present invention further preferably step (1) further includes analyzing the trend of the carbon isotope values of the components in the natural gas with the change of depth in the study area of the oil and gas bearing basin to determine the characteristics of the origin change of natural gas in the vertical direction of the study area of the oil and gas bearing basin; if the methane carbon isotope value shows a trend of gradually becoming lighter from deep to shallow, while the ethane and propane remain basically unchanged as a whole, it reflects the characteristic of the transition from thermogenic gas to biogenic gas from deep to shallow vertically.

[0020] Preferably, step (1) further includes performing geochemical analysis on the oil samples in the oil and gas reservoirs in the study area of the oil and gas bearing basin.

[0021] Preferably, the geochemical analysis includes analyzing the crude oil density, crude oil sulfur content, crude oil group components, total oil carbon isotope, biomarker compounds or saturated hydrocarbon chromatography of the oil samples.

[0022] The present invention further preferably step (1) further includes performing geochemical analysis on the oil samples in the oil and gas reservoirs in the study area of the oil and gas bearing basin, which can trace the generation and evolution history of oil and gas, further verify the origin and composition type of the natural gas in the study area of the oil and gas bearing basin, and at the same time help to reveal the controlling factors and accumulation mechanisms of oil and gas accumulation and establish the oil and gas accumulation model of a specific oil and gas bearing basin.

[0023] Preferably, the analysis in step (2) includes the following steps:

[0024] S1: Restoring the burial depth and temperature of the oil and gas reservoirs in the strata of the study area of the oil and gas bearing basin in the geological history period;

[0025] S2: Analyzing the water medium conditions of the strata in the study area of the oil and gas bearing basin;

[0026] S3: Determining the organic matter nutrient conditions of the source rocks in the layer where the oil and gas are located in the strata of the oil and gas bearing basin.

[0027] The present invention further preferably analyzes the burial depth and temperature, water medium conditions and organic matter nutrient conditions of the source rocks in the study area of the oil and gas bearing basin to determine whether there are conditions for the development of biogenic gas and further confirm the accuracy of the identification of the origin and composition type of natural gas in step (1).

[0028] Preferably, the restoration of the burial depth and temperature of the oil and gas reservoirs in the strata of the study area of the oil and gas bearing basin in step S1 includes: reconstructing the burial history and thermal evolution history of the strata of the oil and gas bearing basin by using the basin simulation method.

[0029] Preferably, the water medium conditions in step S2 include the salinity of water and the pH value of water.

[0030] Preferably, the organic matter nutrient conditions of the source rock in the layer where the oil and gas are located in step S3 include the organic carbon content of the source rock, the hydrocarbon generation potential of the source rock, and the hydrogen index of the source rock.

[0031] It should be noted that the biogenic gas development conditions in the present invention are as follows: historical burial depth < 1500 m (for example, it can be 1300 m, 1200 m, 1000 m, 800 m, etc.), historical geothermal temperature < 80 °C (for example, it can be 75 °C, 60 °C, 50 °C, 40 °C, etc.), a slightly fresh water environment and slightly neutral water medium conditions, the optimal salinity < 35 g / L (for example, it can be 32 g / L, 30 g / L, 28 g / L, 25 g / L, 20 g / L, etc.), the optimal pH is 7.2 - 7.4 (for example, it can be 7.2, 7.3, 7.4, etc.), rich in type III kerogen (that is, the organic matter type is mainly humic type), with a relatively high organic carbon content, the total organic carbon TOC > 0.5% (for example, it can be 0.6%, 0.8%, 1.0%, 1.5%, 2.0%, etc.), and a relatively high hydrocarbon generation potential, S1 + S2 > 1.0 mg / g, for example, it can be 1.5 mg / g, 1.8 mg / g, 2.0 mg / g, 2.2 mg / g, 2.5 mg / g, etc.).

[0032] Among them, S1 + S2 represents the total hydrocarbon amount that can be generated during the pyrolysis of the source rock, including free hydrocarbons and kerogen cracking hydrocarbons, reflecting the hydrocarbon generation ability of the source rock. The higher the value, the stronger the hydrocarbon generation ability of the source rock.

[0033] Preferably, the quantitative analysis in step (3) includes: using the principle of methane carbon isotope conservation and performing the quantitative analysis using the following formula;

[0034]

[0035] Among them, is the proportion of thermogenic gas in methane, with the unit of %; δ 13 C 1(现今实测) is the currently measured value of the methane carbon isotope in the oil and gas reservoir, with the unit of ‰; δ 13 C 1(热成因气) is the methane carbon isotope value of pure thermogenic gas, with the unit of ‰; δ 13 C 1(生物成因气) is the methane carbon isotope value of pure biogenic gas, with the unit of ‰.

[0036] Preferably, the methane carbon isotope value of the pure thermogenic gas is obtained by extending δ 13 C 4 –δ 13 C3 –δ 13 C 2 obtained from the trend line of

[0037] According to the isotope thermodynamics fractionation effect, the thermogenic gas from a single source generally shows a positive sequence characteristic that the carbon isotope composition becomes heavier with the increase of carbon number (δ 13 C 1 <δ 13 C 2 <δ 13 C 3 <δ 13 C 4 ), and the carbon isotope values of each alkane show a linear relationship with the reciprocal of its carbon number.

[0038] Preferably, the methane carbon isotope value of the pure biogenic gas adopts the methane carbon isotope value of the measured biogenic gas in the study area of the oil and gas bearing basin.

[0039] It should be noted that if there is no measured methane carbon isotope data of biogenic gas in the study area of the oil and gas bearing basin, the methane carbon isotope value of typical global biogenic gas is referred to, that is, δ 13 C 1(生物成因气) takes a value of -70‰.

[0040] In the second aspect, the present invention provides a method for quantitatively characterizing the maturity of thermogenic gas in natural gas in an oil and gas bearing basin. On the basis of the method for quantitatively characterizing the mixing ratio in the first aspect, the method for quantitatively characterizing the maturity further includes:

[0041] (4) Establish a relationship diagram of the carbon isotope difference Δ(δ 13 C 2 –δ 13 C 1 ) between ethane and methane and the carbon isotope difference Δ(δ 13 C 3 –δ 13 C 1 ) between propane and methane in the natural gas in the study area of the oil and gas bearing basin, and use the relationship diagram to judge the maturity of the thermogenic gas in the natural gas in the oil and gas bearing basin.

[0042] Since ethane and propane mainly come from thermogenic gas, while methane has both thermogenic and biogenic origins. For the complex mixing situation of thermogenic gas and biogenic gas, if only through the empirical formula of methane carbon isotope and source rock maturity (δ 13 C 1–Ro, where Ro is the maturity), the calculated maturity of the natural gas is on the low side, and it is easy to misidentify a source rock with a low degree of evolution as the gas source. Based on this, the method for quantitatively characterizing the maturity of thermogenic gas in natural gas in the oil and gas bearing basin provided by the present invention effectively eliminates the interference of the biogenic gas on the methane carbon isotope characteristic δ 13 C 1 and accurately calculates the maturity of thermogenic gas in the mixed-source natural gas, can more accurately reflect the thermal evolution degree of the source rock, reveals the generation, migration and accumulation processes of natural gas, and further establishes a more accurate reservoir formation model.

[0043] Preferably, the judgment of the maturity of thermogenic gas in the natural gas of the oil and gas bearing basin in step (4) includes: using the maturity interval ranges divided when Ro>1.5% is 14‰ and -6‰ respectively for judgment.

[0044] The maturity interval ranges include a first interval Ro<0.8% (such as 0.2%, 0.5%, 0.6% or 0.8%, etc.), a second interval Ro = 0.8% - 1.5% (such as 0.8%, 1.0%, 1.2% or 1.5%, etc.) and a third interval Ro>1.5% (such as 1.6%, 1.8% or 2.0%, etc.).

[0045] Preferably, step (4) further includes comparing the gas sources of the thermogenic gas to determine the source of the thermogenic gas.

[0046] Compared with the prior art, the present invention has at least the following beneficial effects:

[0047] (1) The method for quantitatively characterizing the mixed-source ratio of natural gas in the oil and gas bearing basin provided by the present invention determines the origin and composition type of the natural gas in the oil and gas bearing basin by deeply combining the natural gas reservoir formation evolution process, accurately identifies thermogenic gas and biogenic gas, and determines the proportions of the thermogenic gas and the biogenic gas, so as to guide the exploration work to more potential regions and horizons.

[0048] (2) The method for quantitatively characterizing the maturity of thermogenic gas in natural gas in the oil and gas bearing basin provided by the present invention effectively eliminates the interference of the biogenic gas on the methane carbon isotope characteristic δ 13 C 1 and accurately calculates the maturity of thermogenic gas in the mixed-source natural gas, can more accurately reflect the thermal evolution degree of the source rock, and reveals the generation, migration and accumulation processes of natural gas. BRIEF DESCRIPTION OF THE DRAWINGS

[0049] Figure 1 is the natural gas origin plate of the research area of the oil and gas bearing basin in Embodiment 1 of the present invention;

[0050] Figure 2 It is a trend graph of the carbon isotope values of methane, ethane, and propane in the natural gas in the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention changing with the depth of the study area of the hydrocarbon-bearing basin;

[0051] Figure 3 It is a chromatogram of the saturated hydrocarbons of the crude oil in the oil and gas reservoir of Structure A in the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention;

[0052] Figure 4 It is a mass spectrometry diagram of the normal hopane series (m / z 191) and the 25-norhopane series (m / z 177) of the crude oil in the oil and gas reservoir of Structure A in the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention, where H represents the hopane series and D represents the 25-norhopane series;

[0053] Figure 5 It is a diagram of the burial history and thermal history of a single well in Structure B in the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention;

[0054] Figure 6 It is a seismic profile passing through the high point of Structure B in the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention;

[0055] Figure 7 It is a relationship diagram between the hydrogen index (HI) and the pyrolysis peak temperature (Tmax) of the Miocene source rock in the shallow layer of the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention;

[0056] Figure 8 It is a relationship diagram between the C1-C4 carbon isotopes and the reciprocal of their carbon numbers in the natural gas of Structure A in the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention;

[0057] Figure 9 It is a relationship diagram between the C1-C4 carbon isotopes and the reciprocal of their carbon numbers in the natural gas of Structure B in the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention;

[0058] Figure 10 It is a relationship diagram of the difference Δ(δ 13 C 2 –δ 13 C 1 ) between the carbon isotopes of ethane and methane and the difference Δ(δ 13 C 3 –δ 13 C 1 ) between the carbon isotopes of propane and methane in the natural gas of Structure A in the study area of the hydrocarbon-bearing basin described in Embodiment 1 of the present invention;

[0059] Figure 11 It is a relationship diagram of the difference Δ(δ 13 C2 –δ 13 C 1 ) and the carbon isotope difference Δ(δ 13 C 3 –δ 13 C 1 ) relationship diagram;

[0060] Figure 12 is the thermal evolution characteristic diagram of the top surface of the upper member of the Pinghu Formation at the critical moment (5 Ma ago) in the study area of the oil and gas bearing basin described in Example 1 of the present invention;

[0061] Figure 13 is the thermal evolution characteristic diagram of the bottom surface of the upper member of the Pinghu Formation at the critical moment (5 Ma ago) in the study area of the oil and gas bearing basin described in Example 1 of the present invention;

[0062] In the figure: 1, thermogenic gas area; 2, first primary biogenic gas area; 3, secondary biogenic gas area; 4, second primary biogenic gas area; 5, abiogenic gas area. Detailed implementation mode

[0063] The technical solution of the present invention will be further described below with reference to the accompanying drawings and through specific implementation modes. However, the following examples are only simple examples of the present invention and do not represent or limit the scope of the protection of the present invention. The scope of protection of the present invention is subject to the claims.

[0064] Example 1

[0065] This example provides a quantitative characterization method for the mixed source ratio of natural gas and the maturity of thermogenic gas in an oil and gas bearing basin. A certain oil and gas bearing basin in the eastern sea area of China is selected as the research object, which includes Structure A and Structure B. The quantitative characterization method for the mixed source ratio of the natural gas includes the following steps:

[0066] (1) Determine the origin and composition type of natural gas in the study area of the oil and gas bearing basin;

[0067] As Figure 1 shown, first, use the natural gas origin chart formed by the relationship chart with the carbon isotope value of methane in the natural gas as the abscissa and the carbon isotope value of carbon dioxide in the natural gas as the ordinate to determine the origin and composition type of the natural gas; wherein the natural gas origin chart includes thermogenic gas area 1, first primary biogenic gas area 2, secondary biogenic gas area 3, second primary biogenic gas area 4 and abiogenic gas area 5; wherein the first primary biogenic gas area 2 is mainly formed by acetic acid fermentation; the second primary biogenic gas area 4 is mainly formed by CO 2 reduction formation; the secondary biogenic gas area 3 is mainly formed by biodegradation; according to Figure 1It can be known that for the study area of the oil and gas bearing basin, whether it is Structure A or Structure B, compared with the natural gas in the Oligocene, the natural gas in the Miocene has the characteristics of mixed sources of biogenic gas and thermogenic gas, where the biogenic gas includes primary biogenic gas and secondary biogenic gas;

[0068] As Figure 2 shown, by plotting the trend of the carbon isotope values of each component in the natural gas with the depth change in the study area of the oil and gas bearing basin, it can be seen that the methane carbon isotope shows a trend of gradually becoming lighter from deep to shallow, while ethane and propane generally remain basically unchanged as a whole, reflecting the characteristics of the transition from the relatively deep thermogenic gas in the Oligocene to the thermogenic-biogenic mixed gas in the shallow Miocene;

[0069] As Figure 3 and Figure 4 shown, by conducting geochemical analysis on the oil samples in the oil and gas reservoirs in the study area of the oil and gas bearing basin, it can be seen that: the Miocene crude oil has a small amount but relatively complete series of 25-norhopane compounds, indicating that serious biodegradation has occurred, and the n-alkanes in the simultaneously charged crude oil have been completely consumed; however, the distribution of n-alkanes in the saturated hydrocarbon chromatogram of the Miocene crude oil is complete and the peak value is high, and there is no "bulge" phenomenon; the coexistence of such 25-norhopane series compounds and n-alkanes indicates that the Miocene oil and gas reservoir in Structure A has experienced at least two stages of crude oil charging: the first stage of crude oil underwent biodegradation and secondary transformation during or after charging, leaving only a small amount of residual crude oil; the second stage of crude oil charging occurred relatively late, and a large amount of fresh crude oil was charged to form a reservoir;

[0070] (2) Analyze whether the strata in the study area of the oil and gas bearing basin have the development conditions for biogenic gas, including the following steps:

[0071] S1: Restore the burial depth and temperature of the oil and gas reservoirs in the strata of the study area of the oil and gas bearing basin in the geological history period;

[0072] S2: Analyze the water medium conditions of the strata in the study area of the oil and gas bearing basin;

[0073] S3: Determine the organic matter nutrient conditions of the source rocks in the layer where the oil and gas are located in the strata of the oil and gas bearing basin;

[0074] As Figures 5 - 7 shown, the burial depth of the oil and gas reservoir in the strata of Structure B in the study area of the oil and gas bearing basin < 1500 m and the formation temperature < 80 °C in the geological history period. Especially during the uplift and inversion period (13 - 10 Ma ago), the formation temperature of the Miocene strata close to the surface is relatively low; and the Miocene mudstone is rich in type III kerogen, which can provide sufficient nutrients;

[0075] Taking three shallow development wells as examples, the water quality conditions of each well in the strata of the study area of the oil and gas bearing basin are shown in Table 1, and they are all suitable for the development of methanogens;

[0076] Table 1

[0077] Well Name Total Mineralization (g / L) pH Water Type 1 17.24 7.3 Calcium Chloride 2 16.72 7.4 Calcium Chloride 3 19.39 7.0 Calcium Chloride

[0078] (3) Perform quantitative analysis on the mixed-source area determined according to steps (1) and (2) to obtain the ratio of thermogenic gas to biogenic gas in natural gas;

[0079] Utilize the principle of methane carbon isotope conservation and perform the above-mentioned quantitative analysis using the following formula;

[0080]

[0081] Wherein, is the proportion of thermogenic gas in methane, with the unit of %; δ 13 C 1(现今实测) is the currently measured value of methane carbon isotope in the oil and gas reservoir, with the unit of ‰; δ 13 C 1(热成因气) is the methane carbon isotope value of pure thermogenic gas, with the unit of ‰; δ 13 C 1(生物成因气) is the methane carbon isotope value of pure biogenic gas, with the unit of ‰; wherein the methane carbon isotope value of the pure thermogenic gas is obtained by extending the trend line of δ 13 C 4 –δ 13 C 3 –δ 13 C 2 as shown, for Structure A, the methane carbon isotope δ

[0082] such as Figure 8 shown, for Structure A, the methane carbon isotope δ 13 C 1(热成因气) of the pure thermogenic gas is –35‰; the methane carbon isotope value of the pure biogenic gas refers to the methane carbon isotope δ 13 C 1(生物成因气) of typical global biogas and takes the value of -70‰;

[0083] such as Figure 9 shown, for Structure B, the methane carbon isotope value δ 13 C 1(热成因气) of the pure thermogenic gas is –31‰; the methane carbon isotope value of the pure biogenic gas refers to the methane carbon isotope δ 13 C 1(生物成因气) of typical global biogas and takes the value of -70‰;

[0084] According to the above formula, calculate the proportions of thermogenic gas and biogenic gas in methane of Structure A and Structure B, as shown in Table 2;

[0085] Table 2

[0086]

[0087] (4)Quantitatively analyze the maturity of thermogenic gas in the natural gas; including: establishing a relationship diagram between the carbon isotope difference Δ(δ 13 C 2 –δ 13 C 1 ) between ethane and methane in the natural gas in the study area of the oil and gas bearing basin and the carbon isotope difference Δ(δ 13 C 3 –δ 13 C 1 ) between propane and methane in the natural gas, and using the relationship diagram to estimate and judge the maturity of thermogenic gas in the natural gas in the oil and gas bearing basin,

[0088] As Figure 10 shown, the thermogenic gas in Structure A is mainly mature gas, and the thermal maturity is approximately around 1.2%, which is matched with the maturity plane of the upper member of the Pinghu Formation source rock during the key hydrocarbon accumulation period (5 Ma ago) ( Figure 12 and Figure 13 ), thus clarifying that the thermogenic gas mainly comes from the upper member of the Pinghu Formation source rock;

[0089] As Figure 11 shown, the thermogenic gas in Structure B is mainly mature gas, and the thermal maturity is approximately around 1.6%, which is matched with the maturity plane of the upper member of the Pinghu Formation source rock during the key hydrocarbon accumulation period (5 Ma ago) ( Figure 12 and Figure 13 ), thus clarifying that the thermogenic gas mainly comes from the upper member of the Pinghu Formation source rock.

[0090] In summary, the present invention accurately identifies the thermogenic gas and biogenic gas in the study area of the oil and gas bearing basin and quantitatively characterizes the mixed source ratio by deeply combining the natural gas accumulation and evolution process, and at the same time can quickly and accurately calculate the natural gas maturity, and can effectively exclude the interference of biogenic gas on the methane carbon isotope characteristic δ 13 C 1 .

[0091] The applicant declares that the above is only the specific implementation manner of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily thought of by those skilled in the art within the technical scope disclosed by the present invention fall within the protection scope and the public disclosure scope of the present invention.

Claims

1. A method for quantitatively characterizing the mixed source ratio of natural gas in an oil and gas basin, characterized in that: The method for quantitatively characterizing the mixed source ratio of natural gas comprises the following steps: (1) Determine the origin and composition of natural gas in the study area of ​​the petroliferous basin; (2) Analyze whether the strata in the study area of ​​the oil and gas basin have the conditions for the development of biogenic gas; (3) Quantitatively analyzing the mixed source area determined according to step (1) and step (2) to obtain the ratio of thermogenic gas to biogenic gas in the natural gas.

2. The method for quantitatively characterizing the mixed source ratio of natural gas according to claim 1, characterized in that: The step (1) of determining the origin of the natural gas and its composition type comprises: determining the origin of the natural gas and its composition type by analyzing the content of each component in the natural gas and the carbon isotope value of each component; Preferably, analyzing the content of each component in the natural gas and the carbon isotope value of each component includes: determining the origin of the natural gas and its composition type using a natural gas origin chart formed by a relationship diagram with the carbon isotope value of methane in the natural gas as the horizontal axis and the carbon isotope value of carbon dioxide in the natural gas as the vertical axis.

3. The method for quantitatively characterizing the mixed source ratio of natural gas according to claim 1 or 2, characterized in that: Step (1) also includes analyzing the trend of carbon isotope values ​​of each component in the natural gas changing with the depth of the study area of ​​the oil and gas basin.

4. The method for quantitatively characterizing the mixed source ratio of natural gas according to any one of claims 1 to 3, characterized in that: Step (1) also includes geochemical analysis of oil samples in oil and gas reservoirs in the oil and gas basin study area; Preferably, the geochemical analysis includes analyzing the crude oil density, crude oil sulfur content, crude oil group components, whole oil carbon isotopes, biomarker compounds or saturated hydrocarbon chromatography of the oil sample.

5. The method for quantitatively characterizing the mixed source ratio of natural gas according to any one of claims 1 to 4, characterized in that: The analysis in step (2) comprises the following steps: S1: Restore the burial depth and temperature of the oil and gas reservoirs in the strata of the study area of ​​the oil and gas basin during the geological history period; S2: Analyze the water medium conditions of the strata in the study area of ​​the oil and gas basin; S3: Determine the organic nutrient conditions of the source rock at the oil and gas layer in the oil and gas bearing basin.

6. The method for quantitatively characterizing the mixed source ratio of natural gas according to claim 5, characterized in that: Step S1: Restoring the burial depth and temperature of the oil and gas reservoirs in the strata of the oil and gas basin study area during the geological history period includes: reconstructing the burial history and thermal evolution history of the strata of the oil and gas basin using a basin simulation method; Preferably, the water medium conditions in step S2 include the mineralization of water and the pH value of water; Preferably, the organic nutrient conditions of the source rock in the stratum where the oil and gas are located in step S3 include the organic carbon content of the source rock, the hydrocarbon generation potential of the source rock and the hydrogen index of the source rock.

7. The method for quantitatively characterizing the mixed source ratio of natural gas according to any one of claims 1 to 6, characterized in that: The quantitative analysis in step (3) includes: utilizing the methane carbon isotope conservation principle and using the following formula to perform the quantitative analysis; in, is the proportion of thermogenic gas in methane, in %; δ 13 C 1(现今实测) is the current measured value of the carbon isotope of methane in the oil and gas reservoir, in ‰; δ 13 C 1(热成因气) is the carbon isotope value of methane in pure thermogenic gas, in ‰; δ 13 C 1(生物成因气) is the methane carbon isotope value of pure biogenic gas, in ‰.

8. A method for quantitatively characterizing the maturity of thermogenic gas in natural gas in an oil and gas basin, characterized in that: Based on the method for quantitatively characterizing the mixed source ratio according to any one of claims 1 to 7, the method for quantitatively characterizing maturity further comprises: (4) Establish the carbon isotope difference Δ(δ 13 C2–δ 13 C1) and the carbon isotope difference Δ(δ 13 C3–δ 13 C1), and using the relationship diagram to determine the maturity of the thermogenic gas in the natural gas in the oil and gas basin.

9. The method for quantitatively characterizing the maturity of thermogenic gas in natural gas according to claim 8, characterized in that: The determination of the maturity of the thermogenic gas in the natural gas of the oil and gas basin includes: using the Δ(δ 13 C2–δ 13 C1) is judged based on the maturity range divided by 14‰ and –6‰ respectively.

10. The method for quantitatively characterizing the maturity of thermogenic gas in natural gas according to claim 8 or 9, characterized in that: Step (4) also includes performing a gas source comparison on the thermogenic gas to determine the source of the thermogenic gas.

Images