Determination method of matching relationship between trap formation period and hydrocarbon generation amount and its application

Abstract

The present invention provides a method for determining the matching relationship between the trap formation period and the hydrocarbon generation amount, and its application. The method comprises: obtaining the geological parameters of the source rock in the target area, determining the boundary conditions, and establishing a three-dimensional geological model; correcting the three-dimensional geological model with measured data, calculating the hydrocarbon generation amount of the source rock in each geological period, and determining the peak hydrocarbon generation period; restoring the tectonic evolution history profile, determining the trap formation period; and determining the matching relationship between the trap formation period and the peak hydrocarbon generation period. The present invention further provides the application of the above method in the prediction of the exploration prospects of a basin. The above method provided by the present invention provides technical support for selecting areas, belts, and determining favorable targets, provides a powerful reference for conducting oil and gas exploration, and is highly practical.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas exploration, and in particular to a method for determining the matching relationship between trap formation period and hydrocarbon generation amount and its application. Background Art

[0002] Traps are the final site of oil and gas migration and accumulation. Oil and gas generated and expelled from source rocks can only accumulate if they migrate and are preserved in traps; otherwise, they remain dispersed throughout the formation. For a trap to capture oil and gas, it must not only be located along the migration path but also have its formation time precisely aligned with the source rock's period of significant hydrocarbon generation and expulsion. The matching of trap formation with source rock generation in a petroliferous basin is crucial for reservoir formation. Given an effective transport system, traps formed prior to or contemporaneously with the source rock's period of significant hydrocarbon generation and expulsion can capture significant amounts of source rock-expelled oil and gas, resulting in large accumulations within the trap. Conversely, traps formed later than the source rock's period of significant hydrocarbon generation and expulsion may capture oil and gas from damaged earlier reservoirs, forming secondary reservoirs, or may fail to capture oil and gas due to missing the peak of hydrocarbon generation, rendering the trap ineffective. The amount of oil and gas a trap can capture depends on the time difference between the two. The smaller the time difference, the more oil and gas the trap can capture, and the larger the accumulation. Conversely, the smaller the amount of oil and gas captured, the smaller the accumulation. Therefore, analyzing the matching relationship between the trap formation period and the hydrocarbon generation period of the source rock is crucial for predicting the exploration prospects of a basin.

[0003] Lithologic traps form during periods of sealing conditions. These traps form when the reservoir reaches a certain depth and a displacement pressure differential develops between the reservoir and the surrounding rock. Source rocks can only generate oil and gas when buried to a certain depth and maturity. Basin subsidence and uplift can lead to the generation or dissipation of oil and gas. During basin subsidence, source rocks typically undergo thermal evolution due to burial, generating oil and gas. During basin uplift, the source rocks cool, halting thermal evolution and hydrocarbon generation. Furthermore, the tectonic movements associated with uplift can cause large-scale migration of earlier-formed oil and gas, which accumulates and forms reservoirs if they encounter suitable traps. However, erosion caused by intense basin uplift can dissipate oil and gas reservoirs. Repeated tectonic subsidence and uplift within a basin can lead to multiple hydrocarbon generation and accumulations in source rocks. Previous studies primarily simulated the maturity evolution of source rocks in individual wells based on the theory of oil and gas generation through thermal degradation (cracking) of kerogen. Based on the relationship between the evolutionary stages of vitrinite reflectance (Ro) and oil and gas generation, these studies indirectly and qualitatively inferred the history of oil and gas formation. However, these studies were unable to capture the evolution of hydrocarbon generation in source rocks throughout geological history. Furthermore, most simulations were one-dimensional, single-well simulations, unable to reproduce the hydrocarbon generation evolution of source rocks in three-dimensional space at the basin scale. Summary of the Invention

[0004] To address the above-mentioned issues, the present invention aims to provide a method for determining the matching relationship between trap formation period and hydrocarbon generation, and its application. This method can determine the matching relationship between trap formation period and hydrocarbon generation period, providing technical support for selecting areas and zones, and identifying favorable targets, with strong practicality.

[0005] To achieve the above object, the present invention provides a method for determining the matching relationship between trap formation period and hydrocarbon generation amount, the method comprising:

[0006] Obtain geological parameters of source rocks in the target area, determine boundary conditions, and establish a three-dimensional geological model;

[0007] Correcting the three-dimensional geological model using measured data, calculating the hydrocarbon generation amount of the source rock in each geological period, and determining the peak period of hydrocarbon generation;

[0008] Restore the structural evolution history profile and determine the trap formation period;

[0009] Determine the matching relationship between the trap formation period and the peak hydrocarbon generation period;

[0010] The trap formation period includes the geological time of the formation of the structural trap or the formation time of the stratigraphic trap.

[0011] According to a specific embodiment of the present invention, the geological parameters generally include: the correspondence between strata and geological ages, the distribution of source rock thickness, the distribution of organic carbon content in source rocks, kerogen distribution, stratum thickness distribution, the amount of erosion and erosion period of strata, the distribution of stratum sedimentary phases, vitrinite reflectance (Ro) and hydrocarbon generation dynamics parameters of source rocks.

[0012] According to a specific embodiment of the present invention, the method for obtaining the thickness distribution of the source rock may include: drawing a planar isopach map of each set of source rocks in the target area based on drilling data and seismic data of the target area.

[0013] According to a specific embodiment of the present invention, the method for obtaining the organic carbon distribution of the source rock may include: drawing a planar distribution map of the total organic carbon of each set of source rocks in the target area based on the total organic carbon data measured by drilling coring data in the target area.

[0014] According to a specific embodiment of the present invention, the method for obtaining the distribution of stratum thickness may include: drawing thickness contour maps of each set of strata in the source rock based on drilling data and seismic data.

[0015] According to a specific embodiment of the present invention, the method for obtaining the amount of erosion in the formation may include: restoring the amount of erosion in each set of strata in the source rock and drawing a planar distribution map of the amount of erosion in each set of strata. The method for restoring the amount of erosion in each set of strata in the source rock may include one or a combination of two or more of the following: structural cross-section method, acoustic transit time method, and vitrinite reflectance method.

[0016] In a specific embodiment of the present invention, in the process of recovering the amount of formation erosion, the structural cross-section method, as a universal semi-quantitative method, can roughly estimate the amount of formation erosion. This method generally roughly estimates the amount of formation erosion based on the thickness of the uneroded stratum and the distribution characteristics in the plane, and then obtains the planar distribution of the erosion amount based on the estimation results of multiple two-dimensional sections. Compared with the structural cross-section method, the acoustic time difference method and the vitrinite reflectance method can more accurately calculate the amount of erosion of a typical well, but in application, there may be certain requirements for the target area where measured data and the vertical distribution morphology of the measured data may not be obtained. In a specific embodiment, one of the above three methods or a combination of two or more can be selected to recover the amount of formation erosion based on the specific geological conditions and drilling conditions of the target area.

[0017] According to a specific embodiment of the present invention, the method for obtaining the distribution of sedimentary facies of the strata includes: drawing sedimentary facies maps of each set of strata based on drilling data, seismic data, and sedimentary facies marker data of the target area.

[0018] According to a specific embodiment of the present invention, the method for obtaining the kerogen distribution of the source rock includes: drawing a planar distribution map of the kerogen of each set of source rocks based on the kerogen type parameters measured by the drilling coring data of the target area.

[0019] According to a specific embodiment of the present invention, the correspondence between the strata and the geological era can be determined according to the International Chronostratigraphic Chart.

[0020] According to a specific embodiment of the present invention, the hydrocarbon generation kinetic parameters of the source rock generally include the activation energy distribution and frequency factor of oil and gas generation. A method for obtaining the activation energy distribution and frequency factor of oil and gas generation may include: obtaining crude oil through a simulation experiment of oil and gas generation from kerogen thermal degradation, applying the crude oil to a gold tube hydrocarbon generation simulation experiment, obtaining rate curves for oil and gas generation from kerogen degradation at different temperature rates, and obtaining rate curves for gas generation from secondary cracking of the crude oil at different heating rates, and then using these rate curves to calculate the activation energy distribution and frequency factor of oil and gas generation. The activation energy distribution is related to the kerogen type. Before performing hydrocarbon generation simulation calculations, the kerogen type can be determined by using a planar kerogen distribution diagram of each set of source rocks, thereby determining the activation energy parameters to be calculated. The activation energy distribution and frequency factor of oil and gas generation can be calculated using software specifically developed by Lawrence Livermore National Laboratory for hydrocarbon generation kinetics data processing (version: Kinetics05).

[0021] According to a specific embodiment of the present invention, the boundary conditions may include paleosurface temperature, paleowater depth (e.g., the distribution of paleowater depth), and paleoheat flow. The paleowater depth is generally determined based on a lithologic paleogeographic map; the paleosurface temperature can be determined based on the paleolatitude of the target area during its geological history (e.g., the paleotemperature). Figure 8 The paleoheat flow can be determined by combining geothermodynamics with geochemistry, according to the current low temperature of the target area, and by basin simulation software.

[0022] In a specific embodiment of the present invention, taking a well as an example, the method for recovering the ancient heat flow may include: recovering the burial history of a point in the well string, and determining the present heat flow of the burial point according to the following formula (1-1):

[0023]

[0024] Where Q0 is the current heat flow value at that point, mW / m 2 ; is the current average geothermal gradient at the point, ℃ / km; It is the average thermal conductivity of all strata above this point, W / (m·℃).

[0025] Sedimentary basins have relatively stable heat flow values ​​under certain tectonic backgrounds, and sometimes the geothermal gradient is also stable. Therefore, the average thermal conductivity and average geothermal gradient can be calculated based on all strata above the basin base (or the lowest simulated layer). A single well stratigraphic column has a constant heat flow value (Q0) from top to bottom. In this case, the integration path only needs to be taken as the bottom boundary of the lowest stratum.

[0026] After fitting Ro values ​​for many wells in different regions, the optimal form of paleoheat flow variation was determined to be:

[0027] Q(t)=Q0(1+θt) (1-2)

[0028] Where Q(t) is the ancient heat flow value at time t, mW / m 2 ; Q0 is the current heat flow value, mW / m 2 ; t is the geological age at a certain moment in the burial process of the point, Ma; θ is the heat flow relationship factor between ancient and modern times, Ma -1 .

[0029] Equation (1-2) assumes that paleoheat flow varies linearly throughout the geological history, which, to a certain extent, obscures the cyclical nature and complexity of basin evolution. In reality, paleoheat flow in sedimentary basins varies in various ways, including linear, exponential, and fluctuating patterns. Practice has proven that exponential or linear models with segmented recovery are ideal approaches.

[0030] In some embodiments, the method exponential model used to recover paleoheat flow can be:

[0031] Q(t)=Q 0i exp〔θ i (tt i )〕 (i=1,…,m) (1-3)

[0032] Where Q(t) is the heat flow value at time t, mW / m 2 ;Q 0i is the heat flow value at the end of the i-th structural sedimentation period, mW / m 2 θ i is the heat flow relationship factor of the ith tectonic sedimentary period, Ma -1 ;t i is the geological age at the end of the i-th tectonic movement period, Ma.

[0033] In some embodiments, the linear model used to recover paleoheat flow can be:

[0034] Q(t)=Q 0i 〔1+θ i (tt i )〕 (i=1,…,m) (1-4)

[0035] Where Q(t) is the heat flow value at time t, mW / m 2 ;Q 0i is the heat flow value at the end of the i-th structural sedimentation period, mW / m 2 θ i is the heat flow relationship factor of the ith tectonic sedimentary period, Ma-1 ;t i is the geological age at the end of the i-th tectonic movement period, Ma.

[0036] In the specific implementation of the present invention, the inversion geological history method is generally used to determine the relationship between the paleoheat flow changes in each section. Assume that m tectonic movement periods are determined based on the burial history of the stratum, and the mth period is the closest to the present; at this time, Q 0m =Q(0),t m =0, Q(0) is the current surface calorific value (mW / m 2 ); then calculate Q(t according to formula (1-3) or (1-4) m-1 ); in the m-1 period, Q0(m-1)=Q(t m-1 ), and so on, to find the heat flow relationship curve of each period.

[0037] According to a specific embodiment of the present invention, the process of establishing the three-dimensional geological model generally includes: establishing a stratigraphic framework, setting stratigraphic lithology, inputting geological parameters of each set of source rocks, setting boundary conditions, and establishing a three-dimensional geological model.

[0038] According to a specific embodiment of the present invention, during the establishment of the above-mentioned three-dimensional geological model, the method of establishing a stratigraphic framework may include: generating a model top surface according to a ground topographic map, and establishing a stratigraphic framework from top to bottom using a stratigraphic plane isopach map.

[0039] According to a specific embodiment of the present invention, during the establishment of the three-dimensional geological model, the method for setting the formation lithology may include: statistically analyzing pure lithologies based on comprehensive mud logging data from drilling in the target area, and using the generated mixed lithologies as the formation lithology to be set. The target lithofacies for the pure lithology statistics may include one or a combination of two or more of well sandstone, siltstone, mudstone, and carbonate.

[0040] According to a specific embodiment of the present invention, in the process of establishing the above-mentioned three-dimensional geological model, the geological parameters of each set of source rocks input include the thickness of the source rock, the organic carbon content of the source rock, the distribution of sedimentary phases of the formation, the amount of formation erosion and the erosion period, the vitrinite reflectance and the hydrocarbon generation dynamics parameters.

[0041] According to a specific embodiment of the present invention, the measured data used to calibrate the 3D geological model can include measured vitrinite reflectance values ​​of the target area. These measured vitrinite reflectance values ​​can be used as calibration parameters for the maximum burial depth and simulated maturity of the formation. During the calibration of the simulated maturity, the amount of denudation can be determined, and the maximum burial depth can be determined based on the current residual formation thickness.

[0042] According to a specific embodiment of the present invention, the method for calibrating the three-dimensional geological model may include: simulating source rock maturity, using a typical well as a calibration object, simulating source rock maturity, obtaining simulated vitrinite reflectance values ​​(generally performed in the PetroMod 1D module), comparing the measured and simulated vitrinite reflectance values ​​in the typical well, adjusting the erosion and paleoheat flow values ​​to bring the measured and simulated vitrinite reflectance values ​​into closer agreement, and using the erosion and paleoheat flow values ​​corresponding to the maximum agreement between the measured and simulated vitrinite reflectance values ​​as the final values ​​for calculating hydrocarbon generation. The calibration process utilizes the measured and simulated vitrinite reflectance values ​​to jointly adjust the erosion and paleoheat flow values. The erosion and paleoheat flow values ​​at which the measured and simulated vitrinite reflectance values ​​agree most closely with the actual geological evolution of the target area.

[0043] According to a specific embodiment of the present invention, the hydrocarbon generation calculation method may include: using the "PetroReport" module (petroleum module) in PetroMod 3D software (e.g., software developed by Schlumberger, version PetroMod 2012), taking a set of source rocks in a target area as the calculation object, selecting an initial geological time, setting the statistical mode to "Event," converting it to surface conditions, and calculating the oil and gas generation during that time; then selecting a downward shift in geological time, calculating the oil and gas generation using the same method until the oil and gas generation is calculated to the present moment, thereby completing the hydrocarbon generation calculation for a set of source rocks. Using this method, the hydrocarbon generation calculation for multiple sets of source rocks can be completed sequentially.

[0044] According to a specific embodiment of the present invention, the method for restoring the tectonic evolution history profile includes: selecting a seismic profile of the structure, converting it into a depth domain profile after performing tectonic interpretation, and drawing the tectonic evolution history profile based on the principle of balanced profile. According to a specific embodiment of the present invention, the formation time of the stratigraphic trap is determined according to the formation time of the unconformity surface of the tectonic evolution history profile, and the geological time when the tectonic trap is formed is determined according to the tectonic evolution history profile. For example, the formation time of geological morphology (such as anticline morphology, fault) can be obtained based on the tectonic evolution history profile to determine the formation time of the tectonic trap. The restoration of the tectonic evolution history profile can be implemented using the 2Dmove 4.0 software developed by MIDLIAND.

[0045] According to a specific embodiment of the present invention, the matching relationship between the trap formation period and the peak hydrocarbon generation period includes one of the following: the trap formation period is earlier than the peak hydrocarbon generation period, the trap formation period is synchronized with the peak hydrocarbon generation period, or the trap formation period is later than the peak hydrocarbon generation period. When the trap formation period is earlier than the peak hydrocarbon generation period, a large amount of oil and gas discharged from the source rock can be captured, and the amount of oil and gas accumulated in the trap is large. When the trap formation period is later than the peak hydrocarbon generation period, the trap may capture oil and gas in damaged early oil and gas reservoirs, forming secondary oil and gas reservoirs, or fail to capture oil and gas due to missing the peak hydrocarbon generation period, becoming an ineffective trap. The time difference between the trap formation period and the peak hydrocarbon generation period determines the amount of oil and gas that the trap can capture. The smaller the time difference between the trap formation period and the peak hydrocarbon generation period, the larger the oil and gas captured by the trap and the larger the oil and gas accumulation. Conversely, the larger the time difference, the smaller the oil and gas captured by the trap and the smaller the oil and gas accumulation.

[0046] The present invention also provides the application of the aforementioned method for determining the matching relationship between trap formation period and hydrocarbon generation in basin exploration prospect prediction. Using this method in basin exploration prospect prediction can determine the matching relationship between trap formation period and hydrocarbon generation period, providing technical support for selecting areas and belts and identifying favorable targets, and possesses strong practicality.

[0047] The beneficial effects of the present invention are:

[0048] 1. The method provided by the present invention is based on drilling, seismic and geochemical data and utilizes basin simulation technology. It can quantitatively calculate the hydrocarbon generation evolution history of source rocks in a basin and determine the peak period of hydrocarbon generation, realizing the three-dimensional spatial hydrocarbon generation evolution process of source rocks at the basin scale. Compared with the method of using the maturity evolution history of source rocks to infer the hydrocarbon generation history, the calculation results provided by the method provided by the present invention are highly reliable and accurate.

[0049] 2. The method provided by the present invention provides technical support for area selection, belt selection and identification of favorable targets by determining the matching relationship between the trap formation period and the peak hydrocarbon generation period, and provides a powerful reference for oil and gas exploration. It has the characteristics of simple structure, reasonable design, strong practicality and low production cost. BRIEF DESCRIPTION OF THE DRAWINGS

[0050] Figure 1 This is a flow chart of the method for determining the matching relationship between the trap formation period and the hydrocarbon generation amount in Example 1.

[0051] Figure 2 This is a set of plane isopach maps of the source rocks in Example 1.

[0052] Figure 3 This is a planar distribution diagram of total organic carbon of a set of source rocks in Example 1.

[0053] Figure 4 This is a thickness contour map of a set of strata in Example 1.

[0054] Figure 5 This is a corresponding relationship diagram between a set of strata and geological ages in Example 1.

[0055] Figure 6 This is a planar distribution diagram of the erosion amount of a set of strata in Example 1.

[0056] Figure 7 This is the distribution diagram of activation energy and frequency factor of oil and gas generation of two types of kerogen in the target area in Example 1.

[0057] Figure 8 A map of the average surface temperature of the world during different geological periods.

[0058] Figure 9 This is the three-dimensional geological model established in Example 1.

[0059] Figure 10 The figure shows the comparison between the measured value and the simulated value of the vitrinite reflectance of the typical well in Example 1.

[0060] Figure 11 This is a histogram of the total hydrocarbon generation of all source rocks in Example 1 at different geological periods.

[0061] Figure 12 This is a cross-sectional diagram of the structural evolution history in Example 1. DETAILED DESCRIPTION

[0062] In order to have a clearer understanding of the technical features, objectives and beneficial effects of the present invention, the technical solution of the present invention is now described in detail below, but it should not be understood as limiting the scope of implementation of the present invention.

[0063] Example 1

[0064] This embodiment provides a method for determining the matching relationship between trap formation period and hydrocarbon generation amount. Figure 1 The flowchart of this method is shown in Figure 2. Figure 1 As shown, the method includes the following steps:

[0065] 1. Obtain the geological parameters of the source rock in the target area, including the following operations:

[0066] (1) Draw the isopach map of source rocks:

[0067] Taking the northern margin of Qaidam Basin as the research object, based on drilling and seismic data as well as previous research results, the plane isopach maps of various source rocks in the basin were drawn. Figure 2 This is one of the planar isopach maps of the source rocks.

[0068] (2) Draw a planar distribution map of organic carbon in source rocks and a distribution map of kerogen types:

[0069] Based on the total organic carbon (TOC) data and kerogen type parameters measured from the drilling core data, a TOC plane distribution map and a kerogen type plane distribution map were drawn. Figure 3 This is a TOC plane distribution map of one set of source rocks.

[0070] (3) Obtain thickness contour maps, sedimentary phase maps, and geological ages corresponding to each stratum:

[0071] Based on drilling data, seismic data, sedimentary facies marker data, and combined with previous research results, each set of stratigraphic plane isopach maps and sedimentary facies maps were drawn. Figure 4 This is a plane isopach map of one of the strata. Figure 5 The International Chronostratigraphic Chart is used to determine the geological age corresponding to each set of strata.

[0072] (4) Obtain the erosion amount and erosion period of each set of strata:

[0073] Applying the structural cross-section method, we first use seismic and drilling data to establish a regional geological profile. Based on the thickness of the strata in the adjacent areas where no erosion has occurred, we use the curve fitting method to obtain the trend of stratum thickness changes. Then we extrapolate to predict the amount of erosion in the eroded areas, and then complete the restoration of the erosion amount of each set of strata, and compile the following data: Figure 6 The planar distribution of erosion is shown, and the erosion period is determined based on the structural evolution history profile.

[0074] (5) Determine hydrocarbon generation kinetic parameters:

[0075] Experiments were conducted using both open and closed systems to determine hydrocarbon generation kinetic parameters. First, an open system was used to simulate the process of kerogen thermal degradation to generate oil and gas. Then, using the crude oil obtained in the open system experiment, a closed system gold tube hydrocarbon generation simulation experiment was conducted to simulate the process of crude oil thermal cracking to generate natural gas. Based on the results of the above two sets of experiments, the generation rate curves of oil and gas generated by kerogen degradation under different heating rate conditions, and the generation rate curves of gas generated by secondary cracking of crude oil under different heating rate conditions were established. Then, the activation energy distribution and frequency factor of oil and gas generation were calculated using the hydrocarbon generation kinetics data processing software (version: Kinetics05) developed by Lawrence Livermore National Laboratory in the United States. Figure 7 Figure 3 is the activation energy distribution and frequency factor distribution diagram, among which Figure a is the activation energy distribution of kerogen gas generation in the Early Jurassic source rock, Figure b is the activation energy distribution of secondary cracking gas generation in the Early Jurassic source rock, Figure c is the activation energy distribution of kerogen gas generation in the Middle Jurassic source rock, and Figure d is the activation energy distribution of secondary cracking gas generation in the Middle Jurassic source rock.

[0076] 2. Determine boundary conditions

[0077] According to the lithofacies paleogeographic map, the ancient water depth is generally estimated based on the principle of using the present to explain the past. For example, the ancient water depth of the continental facies can be considered to be 0m, the ancient water depth of the shallow sea can be considered to be less than 500m, and the ancient water depth of the deep sea can be considered to be greater than 500m. Figure 8 The paleosurface temperature is determined based on the global surface temperature map of different geological periods shown in Figure 1 (based on Wygrala, BP, 1989—Integrated study of an oil field in the southern Po Basin, Northern Italy. PhD thesis. Cologne: University of Cologne.) and the paleolatitude of the target area in the geological history period of this embodiment. The paleolatitude of the geological history period is determined based on Figure 5 The correspondence between the strata shown and the geological age is determined; the ancient heat flow history and ancient geothermal history of the basin are inferred based on the current geothermal temperature of the basin using the Petrosys basin simulation software by applying a method combining geothermodynamics and geochemistry.

[0078] 3. Use PetroMod 3D software to build a 3D geological model

[0079] Generate the top surface of the model based on the ground topography, from top to bottom, using the stratigraphic plane isopach map (such as Figure 4 ) to establish a stratigraphic framework. The lithologic setting of the formation is mainly based on the comprehensive logging data of the drilling. Through the pure lithologic statistics of sandstone, siltstone, mudstone and carbonate rock in a single well, the lithologic mixer (CreatMix) module of the software generates mixed lithologies. At the same time, the stratigraphic sedimentary phase map, measured vitrinite reflectivity, stratum denudation amount and denudation period, source rock thickness, total organic carbon and hydrocarbon generation dynamics obtained in step 1 are input into the PetroMod 3D software (developed by Schlumberger, version PetroMod 2012). Then, the paleo-water depth, paleo-surface temperature and paleo-heat flow values ​​in step 2 are set as boundary conditions to establish the stratigraphic framework. Figure 9 The three-dimensional geological model is shown.

[0080] 4. Correction of 3D geological model:

[0081] The PetroMod 1D module was used to generate the output of source rock maturity simulation results (i.e., simulated vitrinite reflectance values). Representative wells that were evenly distributed within the target area and representative of the different blocks were selected as calibration targets. The following calibration process was performed for each representative well: Using the PetroMod 1D module, the measured and simulated vitrinite reflectance values ​​of the target wells were compared. The measured and simulated vitrinite reflectance values ​​were then aligned by adjusting the set denudation amount and paleoheat flow values. This calibration process was repeated for each representative well. Figure 10 is the comparison between the measured and simulated values ​​of vitrinite reflectance, Figure 10 Figures a-d show the maximum agreement between the measured and simulated values ​​of the vitrinite reflectance of Well Kun 2, Well Han 2, Well Yashen 3, and Well Yishen 1, respectively. Figure 10 The solid line represents the simulated vitrinite reflectance value, and the scattered dots represent the measured vitrinite reflectance value. The denudation and paleoheat flow values ​​that best match the measured and simulated vitrinite reflectance values ​​are recorded. These values ​​are used as the final values, replacing the initial input denudation and paleoheat flow values, to represent the actual geological evolution process.

[0082] 5. Calculation of hydrocarbon generation:

[0083] Taking the final values ​​of denudation and paleoheat flow set in step 4 as the final values, apply the "PetroReport" module in PetroMod 3D, take a set of source rocks in the target area as the calculation object, select the initial geological time, set the statistical mode to "Event", convert it to surface conditions, and calculate the oil and gas generation (i.e., hydrocarbon generation) within that time; then select the geological time to move downward and calculate the oil and gas generation using the same method, and so on until the calculation reaches the present time.

[0084] Then, the hydrocarbon generation of all geological periods of other source rocks in the target area is calculated according to the above method. When summarizing the results, the hydrocarbon generation of all geological periods of a single set of source rocks can be plotted as a hydrocarbon generation history and a histogram, or the hydrocarbon generation of all source rocks in the same geological period can be accumulated to plot the total hydrocarbon generation history and hydrocarbon generation histogram of all source rocks. In this embodiment, the method of plotting Figure 11 The calculation results are summarized in the form of a histogram of the total hydrocarbon generation of all source rocks shown in Figure 2. Figure 11 It can be seen that the peak period of hydrocarbon generation is N1-N2 2 .

[0085] 6. Restore the structural evolution history profile:

[0086] The seismic profile of the structure was selected and converted into a depth domain profile after structural interpretation. The 2Dmove software (developed by MIDLIAND, version 2Dmove 4.0) was used to draw the following diagram based on the principle of balanced profile. Figure 12 The structural evolution history section shown in Figure 2 is shown in Figure 2. Figure 12 The geological time of formation of the structural trap is determined to be N2 1 .

[0087] 7. Determine the matching relationship between the trap formation period and the peak hydrocarbon generation period:

[0088] Comparing the results of steps 5 and 6 shows that in the target area of ​​this embodiment, the trap formation period coincides with the peak hydrocarbon generation period. This matching result is verified by industrial oil and gas flow obtained from the Lenghu No. 5 well in this area. This demonstrates the high accuracy and reliability of the matching results of the method provided by the present invention in determining the relationship between trap formation and peak hydrocarbon generation. This method can provide technical support for selecting areas and belts, and identifying favorable targets, providing a powerful reference for conducting oil and gas exploration.

Claims

1. A method for determining the matching relationship between trap formation period and hydrocarbon generation amount, the method comprising: Obtain geological parameters of source rocks in the target area, determine boundary conditions, and establish a three-dimensional geological model; The three-dimensional geological model is corrected using measured data to calculate the hydrocarbon generation amount of the source rock in each geological period and determine the peak hydrocarbon generation period. The measured data used to correct the three-dimensional geological model include measured values ​​of vitrinite reflectance in the target area. The method for correcting the three-dimensional geological model includes: using a typical well as a correction object, simulating the maturity of the source rock to obtain simulated values ​​of vitrinite reflectance, comparing the measured values ​​and simulated values ​​of the vitrinite reflectance in the typical well, adjusting the amount of denudation and the paleoheat flow value so that the measured values ​​of the vitrinite reflectance tend to match the simulated values, and using the amount of denudation and the paleoheat flow value corresponding to the maximum degree of agreement between the measured and simulated values ​​of the vitrinite reflectance as the initial value for calculating the hydrocarbon generation amount. The hydrocarbon generation calculation method includes: using the "PetroReport" module in the PetroMod 3D software, taking a set of source rocks in a target area as the calculation object, selecting an initial geological time, setting the statistical mode to "event," converting to surface conditions, and calculating the oil and gas generation within the geological time; then selecting a downward shift in geological time, calculating the oil and gas generation using the same method until the oil and gas generation at the present time is calculated, thereby completing the hydrocarbon generation calculation for a set of source rocks; Restoring a tectonic evolution history profile to determine the trap formation period; wherein the method for restoring the tectonic evolution history profile comprises: selecting a seismic profile through the structure, performing a structural interpretation, converting it into a depth domain profile, and drawing the tectonic evolution history profile based on the principle of balanced profile; Determine the matching relationship between the trap formation period and the hydrocarbon generation peak period; wherein the trap formation period is the geological time of the formation of the structural trap or the formation time of the stratigraphic trap; the stratigraphic trap formation time is determined according to the formation time of the unconformity surface of the structural evolution history profile.

2. The method according to claim 1, wherein The geological parameters of the source rock include the distribution of source rock thickness, the distribution of organic carbon content of the source rock, the distribution of stratum thickness, the amount of erosion and the period of erosion of the stratum, the distribution of sedimentary phases of the stratum, vitrinite reflectance, hydrocarbon generation kinetic parameters of the source rock, kerogen distribution, and the correspondence between strata and geological ages.

3. The method according to claim 2, wherein: The method for obtaining the thickness distribution of the hydrocarbon source rock comprises: drawing a plane isopach map of each set of hydrocarbon source rocks existing in the target area based on drilling data and seismic data of the target area; The method for obtaining the total organic carbon distribution of the source rock comprises: drawing a planar distribution map of the total organic carbon of each set of source rocks existing in the target area based on the total organic carbon data measured by drilling core data in the target area; The method for obtaining the distribution of the stratum thickness includes: drawing thickness contour maps of each set of strata in the source rock based on drilling data and seismic data; The method for obtaining the erosion amount of the stratum includes: restoring the erosion amount of each set of strata in the source rock, and drawing a plane distribution map of the erosion amount of each set of strata; The method for obtaining the distribution of the sedimentary facies of the strata includes: drawing sedimentary facies maps of each set of strata based on drilling data, seismic data, and sedimentary facies marker data of the target area; The hydrocarbon generation kinetic parameters of the source rock include activation energy distribution and frequency factor of oil and gas generation; The method for obtaining the kerogen distribution of the source rock includes: drawing a planar distribution map of the kerogen of each set of source rocks based on the kerogen type parameters measured by the drilling coring data of the target area.

4. The method according to claim 3, wherein: The method for recovering the erosion amount of each set of strata in the source rock includes one or a combination of two or more of the following: structural cross-section method, acoustic wave transit time method, and vitrinite reflectance method.

5. The method according to claim 3, wherein The method for obtaining the activation energy distribution and frequency factor of oil and gas generation includes: obtaining crude oil through a simulation experiment of generating oil and gas by thermal degradation of kerogen, applying the crude oil to a gold tube hydrocarbon generation simulation experiment, obtaining a generation rate curve of oil and gas generated by kerogen degradation under different temperature rate conditions, and obtaining a generation rate curve of gas generated by secondary cracking of crude oil under different heating rate conditions, and then using the above rate curves to calculate the activation energy distribution and frequency factor of oil and gas generation.

6. The method according to claim 1, wherein The boundary conditions include paleosurface temperature, paleowater depth, and paleoheat flow.

7. The method according to claim 6, wherein: The method for determining the boundary conditions includes: the ancient water depth is determined based on the lithologic paleogeographic map; the ancient surface temperature is determined based on the ancient latitude of the target area during the geological history period; the ancient heat flow is determined by combining geothermodynamics with geochemistry and reversely deducing based on the current ground temperature of the target area through basin simulation software.

8. The method according to claim 1, wherein The process of establishing the three-dimensional geological model includes: establishing a stratigraphic framework, setting stratigraphic lithology, inputting geological parameters of each set of source rocks, setting boundary conditions, and establishing the three-dimensional geological model.

9. The method according to claim 8, wherein The method for establishing a stratigraphic framework comprises: generating a model top surface according to a ground topographic map, and establishing a stratigraphic framework from top to bottom using a stratigraphic plane isopach map.

10. The method according to claim 8, wherein The method for setting formation lithology includes: statistically analyzing the pure lithology of a single well based on comprehensive logging data of drilling in a target area, generating mixed lithology by a lithology mixer module, and using the generated mixed lithology as the formation lithology to be set.

11. The method according to claim 10, wherein: The pure lithology includes one or a combination of two or more of sandstone, siltstone, mudstone and carbonate rock.

12. The method according to claim 8, wherein The input geological parameters of each set of source rocks include the thickness of the source rocks, the total organic carbon distribution of the source rocks, the distribution of stratum sedimentary phases, the amount of stratum denudation and the denudation period, the vitrinite reflectance and the hydrocarbon generation kinetic parameters.

13. The method according to claim 1, wherein The geological time when the structural trap was formed is determined based on the structural evolution history profile.

14. The method according to claim 1, wherein The matching relationship between the trap formation period and the hydrocarbon generation peak period includes: the trap formation period is earlier than the hydrocarbon generation peak period, the trap formation period is synchronous with the hydrocarbon generation peak period, and the trap formation period is later than the hydrocarbon generation peak period.

15. A method for predicting the exploration prospects of a basin, which utilizes the method for determining the matching relationship between trap formation period and hydrocarbon generation amount according to any one of claims 1 to 14.

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