Method for evaluating hydrocarbon generation potential of marine hydrocarbon source rock

Abstract

The invention relates to the technical field of oil-gas exploration, in particular to a hydrocarbon generation potential evaluation method for marine hydrocarbon source rocks. On the basis of determining terrestrial source and sea source organic matter proportions of marine facies hydrocarbon source rocks in different sedimentary areas, marine facies hydrocarbon source rock thermal simulation experiments of different terrestrial source / sea source organic matter proportions are carried out, and gaseous hydrocarbon yields of the marine facies hydrocarbon source rocks of different terrestrial source / sea source organic matter proportions and isotope characteristics and activation energy of gaseous hydrocarbons of different maturity degrees are determined; according to generation, storage and cover layer parameters of a research area, selecting a suitable model and giving suitable parameter values, performing numerical simulation on hydrocarbon source rocks with different terrestrial / sea source organic matter proportions, and finally quantitatively determining hydrocarbon generation potential of hydrocarbon source rocks with different sedimentary areas and different terrestrial / sea source organic matter proportions in the research area by combining burial-thermal history evolution of the research area. And obtaining a hydrocarbon generation and expulsion period and a charging process, and determining a main reservoir forming period. Compared with the prior art, the hydrocarbon generation potential evaluation accuracy of the marine hydrocarbon source rock can be greatly improved.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas exploration, and more specifically, to a method for evaluating the hydrocarbon generation potential of marine source rocks. Background Art

[0002] The Paleogene Yacheng Formation in the Qiongdongnan Basin in the northern South China Sea is a proven source rock, which develops basin-margin coal-measure source rocks and marine source rocks related to the near-sag zone - sag zone and delta front. The discovery of gas fields with hundreds of billions of cubic meters such as Yacheng 13-1 in the Yainan Sag in the shallow water area of the western region and Lingshui 17-2 in the deep water area of the Ledong-Lingshui Sag has confirmed that the coal-measure source rocks have good quality and great gas-generation potential and are high-quality gas source rocks. For marine source rocks, it is considered that their quality is worse than that of coal-measure source rocks, and the marine transgression time in the Baodao-Changchang Sag in the eastern region is earlier than that in the Ledong-Lingshui Sag in the western region. Coupled with the lack of exploration breakthroughs, there has been suspicion about the hydrocarbon generation potential of marine source rocks, especially those in the Baodao Sag, and thus the overall research is weak.

[0003] Marine source rocks develop terrigenous organic matter and marine organic matter, and the source composition is complex. The different proportions of the two in different sedimentary areas may lead to differences in hydrocarbon generation potential. However, in the past, it was considered that marine source rocks were mainly dominated by terrigenous organic matter affected by the delta front, ignoring the influence of marine organic matter. Furthermore, the quantitative evaluation of the proportion of terrigenous / marine organic matter in different sedimentary areas and the hydrocarbon generation potential of source rocks with different proportions was not carried out. Only the gaseous hydrocarbon yield of limited source rock samples in the basin was used to represent the hydrocarbon generation potential of marine source rocks for evaluation, without distinguishing the differences in the proportion of terrigenous / marine organic matter in marine source rocks in different sedimentary areas, resulting in inaccurate evaluation of the hydrocarbon generation potential of marine source rocks. Summary of the Invention

[0004] Aiming at the problem that the above-mentioned prior art does not distinguish the differences in the proportion of terrigenous / marine organic matter in marine source rocks in different sedimentary areas, resulting in inaccurate evaluation of the hydrocarbon generation potential of marine source rocks, the present invention provides a method for evaluating the hydrocarbon generation potential of marine source rocks, which can accurately evaluate the hydrocarbon generation potential of marine source rocks.

[0005] To solve the above technical problems, the technical solution provided by the present invention is:

[0006] A method for evaluating the hydrocarbon generation potential of marine source rocks, comprising the following steps:

[0007] S1: Determine the differences in the kerogen macerals in the source rocks of different sedimentary areas in the study area, and calculate the relative proportions of terrigenous organic matter and marine organic matter in different horizons and different sedimentary facies zones. The kerogen macerals and biomarkers in the source rocks have strong indicative significance for the biogenic composition of the source rocks. Macerals are the macroscopic manifestation of the source of organic matter and directly determine the oil and gas generation potential of the source rocks. The sapropel group mainly comes from marine algae and has a high oil generation potential; the exinite group comes from terrigenous higher plants transported by the river-delta system and also has a high oil generation potential; the vitrinite group and inertinite group mainly come from terrigenous higher plants and are mainly gas-generating. Woody plant remains rich in lignin are generally deposited in coarse-grained clastic sediments at the estuary position (mainly the delta front subfacies), while the exinite group rich in lipids is usually deposited together with fine-grained clastics in the relatively low-energy water body of the prodelta and inner neritic sea. Biomarkers are the microscopic manifestation of the source of organic matter, and there are obvious differences in the composition of n-alkanes, isoprenoid alkanes, tricyclic terpanes, and triterpenoids between terrigenous organic matter and marine organic matter. Terrigenous organic matter has higher n-alkanes with high carbon numbers, pristane, bisabolane, and taraxerane, while marine organic matter usually has higher n-alkanes with low carbon numbers, gammacerane, and tricyclic terpanes.

[0008] S2: Select at least two source rock samples with different terrigenous / marine organic matter ratios in the study area and conduct thermal simulation experiments to obtain the heating curve, activation energy distribution, frequency factor, gaseous hydrocarbon yield at different maturities, and natural gas methane carbon isotope corresponding to the source rock samples.

[0009] S3: Establish a geological model of the study area and set a virtual well at the center of the sag in the geological model; based on the thermal simulation experiment data and the characteristics of the source rock, reservoir, and caprock revealed by the source rock samples, assign lithologies to each layer of the virtual well source rock, reservoir, and caprock; then conduct one-dimensional simulation on the virtual well to obtain the hydrocarbon generation conversion rate map corresponding to the source rock samples in the geological period, and analyze the hydrocarbon generation and expulsion periods based on the hydrocarbon generation conversion rate map in the geological period.

[0010] S4: Select a drilled well on the geological model as a reference well, implement the implementation steps for the virtual well in step S3 for the reference well, and determine the hydrocarbon accumulation history in the reference well area.

[0011] S5: Conduct a joint analysis of the analysis results of the hydrocarbon generation conversion rate map obtained in the geological period and the hydrocarbon accumulation history in the drilled well area, corroborate each other, and comprehensively determine the main hydrocarbon expulsion period and the main hydrocarbon accumulation period in the study area.

[0012] Based on the above technical solution, on the basis of determining the proportions of terrigenous and marine organic matters in marine source rocks in different sedimentary areas, thermal simulation experiments of marine source rocks with different terrigenous / marine organic matter ratios are carried out to determine the gaseous hydrocarbon yields, the isotope characteristics and activation energies of gaseous hydrocarbons of marine source rocks with different terrigenous / marine organic matter ratios; then, according to the parameters of source rocks, reservoirs and capping rocks in the study area, a suitable model is selected and suitable parameter values are assigned to conduct numerical simulations of source rocks with different terrigenous / marine organic matter ratios, and combined with the burial-thermal history evolution of the study area, finally, the hydrocarbon generation potential of source rocks with different terrigenous / marine organic matter ratios in different sedimentary areas of the study area is quantitatively determined, the hydrocarbon expulsion and charging periods are obtained, and the main hydrocarbon accumulation periods are determined.

[0013] Preferably, the specific steps of step S1 are as follows: first, microscopic observation of the kerogen macerals is carried out, and based on the optical properties of different macerals, the relative proportions of sapropel group, exinite group, vitrinite group and inertinite group in all organic matters of different samples are determined, and the kerogen macerals of samples in different sedimentary facies and different horizons are quantitatively determined; then, using the partial least squares method, based on the n-alkane parameters ACL, TAR, Paq, the isoprenoid alkane parameter Pr / Ph, the bicyclic cedrane abundance parameter T / C 30 H, the gammacerane abundance parameter Ga / C 30 H, the taraxerane abundance parameter Ta / C 30 H and the tricyclic terpane parameter TT / C 30 H, quantitative evaluation is carried out on samples in different horizons and different sedimentary facies belts in the study area to determine the terrigenous / marine organic matter ratios in different horizons and different sedimentary facies belts in the study area.

[0014] Preferably, in step S2, the thermal simulation experiment is a gold tube hydrocarbon generation thermal simulation experiment under formation conditions in a closed system. The gold tube hydrocarbon generation thermal simulation experiment in a closed system can be used to determine the hydrocarbon generation potential of source rocks, and its advantages are small sample injection volume, controllable heating and pressure increasing rates, good airtightness, and the ability to collect light hydrocarbon components, etc.

[0015] Preferably, in the thermal simulation experiment, the interval between adjacent simulated temperature points is not greater than 24 °C, and each heating curve contains no less than 12 simulated temperature points (number of gold tubes).

[0016] Preferably, in step S2, the experimental temperature in the thermal simulation experiment is also converted into an equivalent vitrinite reflectance (EqVRo) value, and the thermal evolution maturity of the source rock sample is determined according to the equivalent vitrinite reflectance (EqVRo) value data of the source rock sample.

[0017] Preferably, in the step S2, the conversion step of the equivalent vitrinite reflectance value is specifically as follows: First, according to the experimental temperature and time of the thermal simulation experiment, the vitrinite conversion index (VCI) is estimated using a chemical kinetic equation, and then the vitrinite conversion index is converted into a simulated vitrinite reflectance value (Easy%Ro) through an empirical equation based on the activation energy and frequency factor; then a new regression equation is fitted between the vitrinite conversion index value and the measured value of the vitrinite reflectance (Ro) of the hydrocarbon source rock sample, and the simulated vitrinite reflectance value (Easy%Ro) is further converted into an equivalent vitrinite reflectance (EqVRo) value according to the regression equation, so as to reflect the thermal evolution maturity of the experimental sample.

[0018] Preferably, in the step S3, first, based on the thermal simulation experiment data and the equivalent vitrinite reflectance data, a Kinetic model of the hydrocarbon source rock sample is established as a thermal evolution model; then, referring to the relevant parameter characteristics revealed by the hydrocarbon source rock sample, the total organic carbon (TOC) and hydrogen index (HI) of each Kinetic model are assigned values as the initial hydrocarbon source rock conditions for basin simulation in the study area; then one-dimensional simulation of the virtual wellbore is carried out.

[0019] Preferably, in the step S3, the geothermal gradient of the virtual well is also assigned using the geothermal heat flow value of the study area, and the measured vitrinite reflectance (Ro), formation temperature, and the maximum peak temperature of hydrocarbon source rock pyrolysis (Tmax) of the drilled wells in the study area are used as calibration data to calibrate the virtual well. Since there are differences in the geothermal gradient at different sags, which has a great impact on the thermal evolution simulation of hydrocarbon source rocks, the geothermal heat flow value of this area is used to assign values to the virtual well to accurately simulate the thermal evolution process of hydrocarbon source rocks, and the measured vitrinite reflectance (Ro), formation temperature, and the maximum peak temperature of hydrocarbon source rock pyrolysis (Tmax) and other data of the drilled wells in this area are input into the PetroMod software as calibration data for the virtual well to increase the reliability of hydrocarbon source rock thermal simulation.

[0020] Preferably, in the step S3, the hydrocarbon generation conversion rate of the hydrocarbon source rock is 0 - 50% corresponding to the initial hydrocarbon generation and expulsion period, 50% - 80% corresponding to the main hydrocarbon generation and expulsion period, and 80% - 100% corresponding to the hydrocarbon generation and expulsion exhaustion period.

[0021] Preferably, in the step S4, first, a one-dimensional burial history - thermal history map of the reference well is generated, and then the inclusion thermometry data of the reference well is plotted on the one-dimensional burial history - thermal history map, and inclusion homogenization temperature inversion analysis is used to obtain the hydrocarbon accumulation history of the reference well area.

[0022] Advantages of the present invention: Based on determining the proportions of terrigenous and marine organic matters in marine source rocks in different sedimentary areas according to the microscopic composition and biomarker characteristics of the source rocks, the present invention conducts thermal simulation experiments on marine source rocks with different terrigenous / marine organic matter ratios under a closed system to determine the gaseous hydrocarbon yields of marine source rocks with different terrigenous / marine organic matter ratios, the gaseous hydrocarbon isotope characteristics and activation energies at different maturities; on this basis, according to the parameters of the source, reservoir and cap rocks in the study area, a suitable model is selected and suitable parameter values are assigned to conduct numerical simulation of source rocks with different terrigenous / marine organic matter ratios, and combined with the homogenization temperature distribution of reservoir inclusions and burial-thermal history evolution in the study area, finally, the hydrocarbon generation potential of source rocks with different sedimentary areas and different terrigenous / marine organic matter ratios in the study area can be quantitatively determined, the hydrocarbon generation and expulsion periods and the charging process can be obtained, and the main hydrocarbon accumulation period can be determined. Compared with the existing evaluation methods, the present invention can greatly improve the accuracy of evaluating the hydrocarbon generation potential of marine source rocks. Brief Description of the Drawings

[0023] Figure 1 is a flow chart of a method for evaluating the hydrocarbon generation potential of marine source rocks;

[0024] Figure 2 is a graph showing the changing trends of microscopic components, biomarkers and organic matter content of source rocks in different horizons and different sedimentary facies belts;

[0025] Figure 3 is a curve graph showing the relationship between the heating range and the equivalent vitrinite reflectance in the thermal simulation experiment;

[0026] Figure 4 is a curve graph showing the changing trend of the gaseous hydrocarbon yield of two source rock samples with maturity;

[0027] Figure 5 is a graph of natural gas methane carbon isotope corresponding to different maturities;

[0028] Figure 6 is a distribution map of activation energies of marine source rocks with different terrigenous / marine organic matter ratios;

[0029] Figure 7 is a forward conversion rate curve graph of marine source rocks with different terrigenous / marine organic matter ratios;

[0030] Figure 8 is a single-point burial-thermal history evolution graph. Detailed Embodiments

[0031] The following are specific descriptions of the technical solutions of the present invention through specific embodiments and in combination with the drawings:

[0032] Example 1

[0033] This embodiment is the first embodiment of a method for evaluating the hydrocarbon generation potential of marine source rocks. Taking the Baodao Sag in the eastern part of the Qiongdongnan Basin as the research object, the proportions of terrigenous and marine organic matters in different sedimentary areas are determined through the microscopic texture and biomarker characteristics of marine source rocks. Thermal simulation experiments of source rocks with different proportions are carried out to obtain the gaseous hydrocarbon yields of marine source rocks with different proportions, the isotope characteristics of gaseous hydrocarbons at different maturities, etc. On this basis, a suitable model is selected, suitable parameters are assigned, numerical simulations of source rocks with different proportions are carried out, the hydrocarbon generation potential of source rocks in different sedimentary areas and with different proportions of terrigenous and marine organic matters in the study area is determined, and then the hydrocarbon generation and expulsion periods and the charging process of the corresponding source rocks are obtained, the main hydrocarbon accumulation period in the study area is determined, the favorable exploration areas are clarified, and the exploration deployment is supported. The method specifically includes the following steps:

[0034] S1: Determine the differences in the kerogen maceral components in the source rocks of different sedimentary areas in the study area, and calculate the relative proportions of terrigenous organic matter and marine organic matter in different horizons and different sedimentary facies belts. Taking the Qiongdongnan Basin as an example, first observe the kerogen maceral components under the microscope, and based on the optical properties of different maceral components, determine the relative proportions of sapropel group, exinite group, vitrinite group and inertinite group in all organic matters of different samples, and quantitatively determine the kerogen maceral components of samples in different sedimentary facies and different horizons (as shown on the left below), as the basis for verifying the calculation results of the proportions of terrigenous and marine organic matters and determining the proportions of terrigenous and marine organic matters in different sedimentary areas; then use the partial least squares method, based on the n-alkane parameters ACL, TAR, Paq, the isoprenoid alkane parameter Pr / Ph, the bicyclic juniperane abundance parameter T / C Figure 2 H, the gammacerane abundance parameter Ga / C 30 H, the taraxerane abundance parameter Ta / C 30 H, and the tricyclic terpane parameter TT / C 30 H, quantitatively evaluate the samples in different horizons and different sedimentary facies belts in the study area, and determine the terrigenous / marine organic matter ratio in different horizons and different sedimentary facies belts in the study area (as shown on the left below). The average ratio of terrigenous organic matter to marine organic matter in the source rocks of the delta front calculated in this step is about 7:3, and the average ratio of terrigenous organic matter to marine organic matter in the source rocks of the prodelta and inner neritic is about 6:4 (as shown on the right below). 30 H, quantitatively evaluate the samples in different horizons and different sedimentary facies belts in the study area, and determine the terrigenous / marine organic matter ratio in different horizons and different sedimentary facies belts in the study area (as shown on the left below). The average ratio of terrigenous organic matter to marine organic matter in the source rocks of the delta front calculated in this step is about 7:3, and the average ratio of terrigenous organic matter to marine organic matter in the source rocks of the prodelta and inner neritic is about 6:4 (as shown on the right below). Figure 1 left), the average ratio of terrigenous organic matter to marine organic matter in the source rocks of the delta front calculated in this step is about 7:3, and the average ratio of terrigenous organic matter to marine organic matter in the source rocks of the prodelta and inner neritic is about 6:4 (as shown on the right below). Figure 2 right).

[0035] S2: Select two source rock samples with different ratios of terrigenous to marine organic matter in the study area, namely the delta front sample with a terrigenous to marine organic matter ratio of 7:3 and the prodelta-inner neritic sample with a ratio of 6:4. The relevant parameters of the two samples are shown in Table 1. The samples have relatively low maturity and relatively high organic matter abundance. Then, perform a thermal simulation experiment under formation conditions. The temperature increase in the experiment first rapidly rises from room temperature to 200 °C (corresponding to an approximate maturity of about 0.5% of the selected source rock samples), and then rises to the required simulated temperature at heating rates of 2 °C / h and 20 °C / h respectively, obtaining two corresponding heating curves. Considering that the overall type of source rocks in the Qiongdongnan Basin in the study area is type II2-III, mainly generating gas and supplemented by oil generation, shift the heating interval backward and set it as 300-650 °C. Then continue to obtain the activation energy distribution, frequency factor, gaseous hydrocarbon yield at different maturities, and natural gas methane carbon isotope corresponding to the source rock samples.

[0036] Table 1 Organic geochemical parameters of thermal simulation cuttings samples

[0037]

[0038] The temperature in this experiment is converted into an equivalent vitrinite reflectance (Easy%Ro) value using the Easy%Ro model of Sweeney and Burnham (1990). The Easy%Ro model uses a chemical kinetic equation to estimate the vitrinite conversion index (VCI), and then uses an empirical equation to calculate the equivalent vitrinite reflectance (Easy%Ro) value through the vitrinite conversion index (VCI); then combine the vitrinite conversion index (VCI) value calculated using the kinetic parameters in the Easy%Ro model of Tang et al. (1996) with the measured value of the vitrinite reflectance (R o ) of the source rock sample to fit a new regression equation, and further convert the Easy%Ro value into an equivalent vitrinite reflectance (EqVRo) value to reflect the thermal evolution maturity of the experimental sample. As Figure 3 shown, the heating interval of this experiment is 300-650 °C, corresponding to an equivalent vitrinite reflectance of 0.6-3.5%.

[0039] The experimental results show that there are obvious differences in the gaseous hydrocarbon yields of samples with different source proportions. As Figure 4 shown, generally, the gaseous hydrocarbon yields of the delta front sample with a terrigenous to marine organic matter ratio of 7:3 and the prodelta-inner neritic sample with a ratio of 6:4 both show a linear increasing trend with the increase in maturity, and the methane carbon isotope shows a trend of becoming heavier. In contrast, the gaseous hydrocarbon yield of the prodelta-inner neritic sample with a terrigenous to marine organic matter ratio of 6:4 is significantly higher than that of the delta front sample with a ratio of 7:3, and at R oWhen it is <2.0%, the hydrocarbon generation rate is significantly higher, about 2-3 times that of the delta front samples. The methane carbon isotope with the same maturity is lighter, such as Figure 5 shown. The activation energy distribution of marine source rocks with different proportions of terrestrial and marine organic matters was obtained through simulation experiments (as shown in Figure 6 ), the gaseous hydrocarbon production rate at different maturities (as shown in Figure 2 ), and the corresponding natural gas methane carbon isotope at different maturities (as shown in Figure 5 ), which were used as the parameter assignment for the forward numerical simulation of the source rock below. And it can provide a basis for identifying the maturity of natural gas through the methane carbon isotope of natural gas for the subsequent discovered oil and gas structures.

[0040] S3: Establish a geological model of the study area and set a virtual well at the center of the depression in the geological model. Since the buried depth of the hydrocarbon generation depression is large and there is no drilling to uncover the complete formation, a virtual wellbore is selected at the center of the depression in this step to simulate the thermal evolution process of the source rock in the depression. Then, based on the thermal simulation experiment data and the characteristics of the source rock, reservoir, and caprock revealed by the source rock samples, the lithologies of each layer of the virtual well source rock, reservoir, and caprock are assigned. Since there are differences in the geothermal gradients of different depressions, which have a great impact on the thermal evolution simulation of the source rock, the geothermal heat flow value of this area is also used to assign values to the virtual well to accurately simulate the thermal evolution process of the source rock. And the measured vitrinite reflectance (Ro), formation temperature, and the maximum peak temperature of source rock pyrolysis (Tmax) and other data of the drilled wells in this area are input into the PetroMod software as the calibration data of the virtual well to increase the reliability of the source rock thermal simulation. Using the relevant parameters obtained from the above thermal simulation, mainly including activation energy data and frequency factor data, a corresponding Kinetic model is established in the PetroMod software, corresponding to ① terrestrial organic matter (the ratio of terrestrial organic matter to marine organic matter is 7:3) and ② marine organic matter (the ratio of terrestrial organic matter to marine organic matter is 6:4), and referring to the relevant parameter characteristics revealed by the drilled wells, the total organic carbon (TOC), hydrogen index (HI) and other parameters of the above two models are assigned. This time, referring to the planar distribution of the total organic carbon content (TOC), hydrogen index (HI) of the source rock in the Qiongdongnan Basin and the single-well measured data, the TOC of terrestrial organic matter is assigned as 2.0% and the HI is assigned as 260 mg / gTOC, and the TOC of marine organic matter is assigned as 4.0% and the HI is assigned as 380 mg / gTOC, which are used as the initial source rock conditions for basin simulation.

[0041] Then, based on the above steps, use the PetroMod software to perform one-dimensional simulation on the virtual well set near the hydrocarbon generation center, export the hydrocarbon generation conversion rate map corresponding to the geological period of the source rock sample, and analyze the hydrocarbon generation and expulsion periods according to the hydrocarbon generation conversion rate map of the geological period.

[0042] S4: Select a drilled well in the geological model as the reference well, perform the implementation steps for the virtual well in step S3 on the reference well, export the one-dimensional burial history-thermal history diagram of this well, plot points on the one-dimensional burial history-thermal history diagram using the inclusion temperature measurement data of this well, and use the homogenization temperature of the inclusions for inversion analysis to determine the hydrocarbon accumulation history of this well area.

[0043] S5: Conduct a joint analysis of the analysis results of the hydrocarbon generation conversion rate diagram of the obtained geological periods and the hydrocarbon accumulation history of the drilled well area to comprehensively determine the main hydrocarbon expulsion period and the main hydrocarbon accumulation period of the study area. Since there may be multiple solutions in the inversion analysis of the hydrocarbon accumulation history using inclusions, there should be a certain overlap in time between the main hydrocarbon accumulation period of the well area and the main hydrocarbon expulsion period of the source rock. Therefore, the hydrocarbon accumulation period obtained by inversion in the well area and the hydrocarbon generation conversion rate diagram of the virtual wellbore in the geological period can be jointly analyzed and corroborated with each other to comprehensively determine the main hydrocarbon expulsion and the main hydrocarbon accumulation period.

[0044] Analysis of the implementation results of this embodiment: As Figure 7 shown, during the period of 30 - 21 Ma, the hydrocarbon generation conversion rates of both types of organic matter were lower than 50%, and they did not have the ability to supply hydrocarbons on a large scale; during the period of 21 - 18 Ma, the hydrocarbon generation conversion rate of terrigenous organic matter reached 50% - 80%, and the hydrocarbon generation conversion rate of marine organic matter was lower than 5%. This stage was the main hydrocarbon generation period of terrigenous organic matter and had the condition of supplying a large amount of hydrocarbons; during the period of 18 - 10.5 Ma, the hydrocarbon generation conversion rate of terrigenous organic matter reached 80% - 90%, and the hydrocarbon generation conversion rate of marine organic matter reached 5% - 50%. It was in a complementary stage and had the ability to supply hydrocarbons on a small scale; during the period of 10.5 - 8 Ma, the hydrocarbon generation conversion rate of terrigenous organic matter reached 90% - 95%, and the hydrocarbon generation conversion rate of marine organic matter reached 50% - 80%. In this stage, the hydrocarbon generation potential of terrigenous organic matter had been exhausted, and marine organic matter was in the main hydrocarbon generation period and had the condition of supplying a large amount of hydrocarbons; during the period of 8.5 - 0 Ma, the hydrocarbon generation potentials of both types of organic matter had been exhausted, and they no longer had the ability to generate hydrocarbons on a large scale. In summary, there were two hydrocarbon generation peak periods in the study area, corresponding to 21 - 18 Ma (the main hydrocarbon generation peak of terrigenous organic matter) and 10.5 - 8 Ma (the main hydrocarbon generation peak of marine organic matter) respectively. Through comprehensive analysis of the homogenization temperature of the coexisting brine inclusions of the reservoir hydrocarbon inclusions and the burial-thermal history, it was determined that the study area experienced 3 periods of hydrocarbon charging, namely 22.5 - 18 Ma, 16 - 7 Ma, and 5.5 - 0 Ma, as specifically shown in Figure 5 shown. Combining with the forward modeling results, the first and second periods of hydrocarbon charging processes corresponded to the main hydrocarbon generation peaks of terrigenous organic matter (21 - 18 Ma) and marine organic matter (10.5 - 8 Ma) respectively.

[0045] Advantages of this embodiment: Based on determining the proportions of terrigenous and marine organic matters in marine source rocks in different sedimentary areas based on the microscopic composition and biomarker characteristics of source rocks, thermal simulation experiments on marine source rocks with different terrigenous / marine organic matter ratios are carried out under a closed system to determine the gaseous hydrocarbon yields of marine source rocks with different terrigenous / marine organic matter ratios, the gaseous hydrocarbon isotope characteristics and activation energies at different maturities; on this basis, according to the parameters of source, reservoir and cap rocks in the study area, a suitable model is selected and suitable parameter values are assigned to conduct numerical simulations of source rocks with different terrigenous / marine organic matter ratios, and combined with the homogenization temperature distribution of reservoir inclusions and burial-thermal history evolution in the study area, finally, the hydrocarbon generation potential of source rocks with different sedimentary areas and different terrigenous / marine organic matter ratios in the study area can be quantitatively determined, the hydrocarbon generation and expulsion periods and the charging process can be obtained, and the main hydrocarbon accumulation period can be determined. Compared with the existing evaluation methods, this embodiment can greatly improve the accuracy of evaluating the hydrocarbon generation potential of marine source rocks.

[0046] Embodiment 2

[0047] This embodiment is the second embodiment of a method for evaluating the hydrocarbon generation potential of marine source rocks. On the basis of Embodiment 1, this embodiment further supplements and explains step S2.

[0048] Furthermore, in the thermal simulation experiment, the interval between adjacent simulation temperature points is not greater than 24 °C, and each heating curve contains no less than 12 simulation temperature points (number of gold tubes).

[0049] Other features, working principles and advantages of this embodiment are the same as those of Embodiment 1.

[0050] Embodiment 3

[0051] This embodiment is the third embodiment of a method for evaluating the hydrocarbon generation potential of marine source rocks. On the basis of Embodiment 2, this embodiment further supplements and explains step S3.

[0052] Furthermore, in step S3, the hydrocarbon generation conversion rate of the source rock is 0 - 50% corresponding to the initial hydrocarbon generation and expulsion period, 50% - 80% corresponding to the main hydrocarbon generation and expulsion period, and 80% - 100% corresponding to the exhaustion period of hydrocarbon generation and expulsion.

[0053] Other features, working principles and advantages of this embodiment are the same as those of Embodiment 2.

[0054] Obviously, the above embodiments of the present invention are merely examples for clearly illustrating the present invention, rather than limitations on the implementation manners of the present invention. For those of ordinary skill in the art, other different forms of changes or modifications can be made based on the above description, and it is not necessary and impossible to enumerate all the implementation manners here. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principle of the present invention shall be included within the protection scope of the claims of the present invention.

Claims

1. A method for evaluating the hydrocarbon generation potential of marine source rocks, characterized in that, Including the following steps: S1: Determine the differences in the kerogen macerals in the source rocks of different sedimentary areas in the study area, and calculate the relative proportions of terrigenous organic matter and marine organic matter in different horizons and different sedimentary facies belts; S2: Select at least two source rock samples with different terrigenous / marine organic matter ratios in the study area, conduct pyrolysis simulation experiments, and obtain the heating curves, activation energy distributions, frequency factors, gaseous hydrocarbon yields at different maturities, and natural gas methane carbon isotopes corresponding to the source rock samples at different maturities; S3: Establish a geological model of the study area, and set a virtual well at the center of the sag in the geological model; Based on the pyrolysis simulation experiment data and the characteristics of the source rock, reservoir, and caprock revealed by the source rock samples, assign lithologies to each layer of the virtual well source rock, reservoir, and caprock, and establish a thermal evolution model corresponding to the source rock samples; Then conduct one-dimensional simulation on the virtual well to obtain the hydrocarbon generation conversion rate map corresponding to the source rock samples in the geological period, and analyze the hydrocarbon generation and expulsion periods according to the hydrocarbon generation conversion rate map in the geological period; S4: Select a drilled well as a reference well on the geological model, implement the steps for the virtual well in step S3 for the reference well, and determine the hydrocarbon accumulation history in the reference well area; S5: Conduct a combined analysis of the analysis results of the hydrocarbon generation conversion rate map in the geological period obtained and the hydrocarbon accumulation history in the drilled well area to determine the main hydrocarbon expulsion period and the main hydrocarbon accumulation period in the study area.

2. The method for evaluating the hydrocarbon generation potential of marine source rocks according to claim 1, wherein The specific steps of the step S1 are as follows: First, microscopic observation of the kerogen macerals is carried out. According to the optical properties of different macerals, the relative proportions of sapropelinite, exinite, vitrinite, and inertinite in all organic matter of different samples are determined, and the kerogen macerals of samples in different sedimentary facies and different horizons are quantitatively determined. Then, using the partial least squares method, based on the n-alkane parameters ACL, TAR, Paq, the isoprenoid alkane parameter Pr / Ph, the bicyclic juniperane abundance parameter T / C 30 H, the gammacerane abundance parameter Ga / C 30 H, the taraxerane abundance parameter Ta / C 30 H and the tricyclic terpane parameter TT / C 30 H, quantitative evaluation is carried out on samples in different horizons and different sedimentary facies belts in the study area to determine the proportions of terrigenous / marine organic matter in different horizons and different sedimentary facies belts in the study area.

3. The method for evaluating the hydrocarbon generation potential of marine source rocks according to claim 2, characterized in that In step S2, the pyrolysis simulation experiment is a gold tube pyrolysis simulation experiment under formation conditions in a closed system.

4. A method for evaluating the hydrocarbon generation potential of marine source rocks according to claim 3, characterized in that, In the pyrolysis simulation experiment, the interval between adjacent simulation temperature points is not greater than 24 °C, and each heating curve contains no less than 12 simulation temperature points (number of gold tubes).

5. A method for evaluating the hydrocarbon generation potential of marine source rocks according to claim 1, characterized in that, In step S2, the experimental temperature in the pyrolysis simulation experiment is also converted into an equivalent vitrinite reflectance value, and then the thermal evolution maturity of the source rock samples is determined according to the equivalent vitrinite reflectance value data of the source rock samples.

6. The method for evaluating the hydrocarbon generation potential of marine source rocks according to claim 1, characterized in that, In step S2, the conversion steps of the equivalent vitrinite reflectance value are specifically as follows: First, estimate the vitrinite transformation index using the chemical kinetic equation according to the experimental temperature and time of the pyrolysis simulation experiment, and then convert the vitrinite transformation index into a simulated vitrinite reflectance value through an empirical equation based on the activation energy and frequency factor; Then, fit a new regression equation between the vitrinite transformation index value and the measured vitrinite reflectance value of the source rock samples, and further convert the simulated vitrinite reflectance value into an equivalent vitrinite reflectance value according to the regression equation.

7. A method for evaluating the hydrocarbon generation potential of marine source rocks according to claim 5, characterized in that, In step S3, first establish the Kinetic model of the source rock samples as the thermal evolution model based on the pyrolysis simulation experiment data and the equivalent vitrinite reflectance data; Then, refer to the relevant parameter characteristics revealed by the source rock samples, assign values to the total organic carbon (TOC) and hydrogen index (HI) of each Kinetic model as the initial source rock conditions for basin simulation in the study area; Then conduct one-dimensional simulation on the virtual wellbore.

8. The method for evaluating the hydrocarbon generation potential of marine source rocks according to claim 7, wherein In the step S3, the geothermal gradient of the virtual well is also assigned by using the terrestrial heat flow value of the study area, and the measured vitrinite reflectance, formation temperature and maximum peak temperature of hydrocarbon source rock pyrolysis of the drilled wells in the study area are used as calibration data to calibrate the virtual well.

9. The method for evaluating the hydrocarbon generation potential of marine source rocks according to claim 1, wherein, In the step S3, the hydrocarbon generation conversion rate of the hydrocarbon source rock is 0-50% corresponding to the initial hydrocarbon generation and expulsion period, 50%-80% corresponding to the main hydrocarbon generation and expulsion period, and 80%-100% corresponding to the hydrocarbon generation and expulsion exhaustion period.

10. The method for evaluating the hydrocarbon generation potential of marine hydrocarbon source rocks according to claim 1, characterized in that, In the step S4, first generate the one-dimensional burial history-thermal history diagram of the reference well, then project points on the one-dimensional burial history-thermal history diagram by using the inclusion thermometry data of the reference well, and use the homogenization temperature of the inclusions for inversion analysis to obtain the hydrocarbon accumulation history of the reference well area.

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