A method for correcting stratum erosion using two-dimensional simulation

Abstract

The present invention discloses a method for correcting formation erosion using two-dimensional simulation, comprising: 1: restoring the formation erosion thickness during a typical tectonic movement period in a study area; 2: obtaining a plane contour map of the erosion thickness of the top surface of a typical structure in the study area, selecting a typical well, and obtaining the formation erosion thickness of each typical well during the typical tectonic movement period; 3: performing a one-dimensional oil and gas accumulation simulation on each typical well; 4: intercepting a two-dimensional seismic profile through the typical well and performing a two-dimensional oil and gas accumulation simulation to obtain a two-dimensional dynamic oil and gas accumulation evolution process map of the intercepted profile; 5: setting a virtual well, comparing its one-dimensional oil and gas accumulation simulation results with the fluid inclusion analysis results of the actual target layer in the study area, and if the results do not match, correcting the formation erosion thickness, and repeating steps 2-5 based on the corrected formation erosion thickness until the formation erosion thickness is accurate. The present invention effectively solves the technical problem that the existing technology cannot accurately calculate the formation erosion amount.

Description

Technical Field

[0001] The present invention belongs to the technical field of oil and gas exploration, relates to reservoir evolution simulation technology, and specifically relates to a method for correcting stratum erosion using two-dimensional simulation, which is particularly suitable for correcting stratum erosion in deep and ultra-deep layers. Background Art

[0002] Following the long-term exploration and development of shallow and intermediate oil and gas fields worldwide, most major oil fields have now entered the late stages of development. Furthermore, with the increasing sophistication of oil and gas exploration, achieving significant breakthroughs in the shallow and intermediate layers of basins is becoming increasingly difficult. Therefore, extending exploration into deep and ultra-deep strata has become an inevitable trend. Furthermore, with advancements in oil and gas drilling technology and the continued deepening of exploration efforts, deep and ultra-deep oil and gas exploration is receiving increasing attention, potentially becoming a key area for future reserve growth. Simply put, achieving significant breakthroughs in oil and gas exploration in shallower strata is already difficult, necessitating the need to explore deeper underground.

[0003] Currently, it has been discovered globally that the porosity and permeability of carbonate reservoirs show a regular decrease with increasing burial depth. However, the porosity variation of carbonate reservoirs in my country with increasing burial depth is much more complex, even showing a continuous increase or cyclical increase and decrease, reflecting the complex characteristics of multi-stage tectonic changes and transformations in superimposed basins and the control of multiple factors. Therefore, the exploration of carbonate oil and gas reservoirs in my country is difficult and costly. Uncovering and understanding the regularity of the formation and distribution of deep and ultra-deep carbonate oil and gas reservoirs and continuously improving oil and gas exploration results are the inevitable development paths for China's oil and gas exploration.

[0004] Basin burial evolution can be used to understand the regularities in the formation and distribution of carbonate oil and gas reservoirs. This process is fundamental to basin analysis and the study of the dynamics of oil and gas migration and accumulation. It is crucial not only for reconstructing basin tectonic and sedimentary evolution but also for analyzing the generation, expulsion, migration, and accumulation of hydrocarbons in oil and gas-bearing basins and estimating resource abundance. The uplift and erosion of basin strata are the result of changes in the basin's burial and sedimentary environment. The intensity and regional variations in stratal erosion reflect the tectonic and sedimentary changes at the time. Basin sedimentary and erosional evolution control changes in the basin's geothermal field, and the undulation of tectonic stratigraphy constrains the direction of oil and gas migration and accumulation. By simulating and reconstructing basin burial history based on the current stratigraphic framework and estimates of stratum erosion during various erosion periods, we can understand the structural morphology of the basin at different historical stages, its evolutionary processes, and the influence of its evolutionary history on the formation of oil and gas deposits. This allows for the quantitative prediction and evaluation of potential drilling targets with high oil and gas enrichment, thereby reducing exploration risk.

[0005] At present, how to accurately calculate the amount of stratum erosion has always been one of the core and difficulties in restoring the burial history of the basin. The methods for calculating the amount of stratum erosion are usually as follows:

[0006] The first method is to use logging data to calculate the amount of formation erosion - the acoustic time difference method

[0007] Under normal compaction, the porosity of clastic rocks varies continuously with depth, with shaly rocks showing an exponential curve and sandstones a straight line. Using sonic logging curves to observe these changing trends can be used to determine erosion. Because the standard exponential relationship between rock acoustic transit time and depth does not change due to erosion, a standard exponential curve can be constructed through statistical fitting of existing acoustic transit time data. In areas of erosion, when the thickness of sediment above the unconformity is less than the erosion thickness, the compaction trend line of the mudstone below the unconformity is extended to Δt (paleosurface). The distance between the paleosurface and the unconformity is the erosion thickness.

[0008] However, this method is only applicable to estimating the erosion thickness of unconformities with large erosion volumes and shallow burial depths. When the burial depth reaches a certain level, there is a deviation between the acoustic wave measurement values ​​calculated using the standard exponential relationship and the actual measured values. This indicates that it is less applicable to areas where the erosion volume is small or the eroded layer has a low degree of diagenesis.

[0009] The second method is to use logging data to calculate the amount of formation erosion - formation comparison method

[0010] The intact sedimentary strata in the adjacent denudation zone are used as references, and the errors mainly come from the geological comparison of long-distance or structurally unstable areas and the geological comparison of unconformable and underdeveloped areas.

[0011] (1) Assume that the original formation thicknesses at points A and B are HA and HB respectively, and the distance between the two points is L. Then the rate of change of formation thickness at points AB and its vicinity is H1 = (HB - HA) / L.

[0012] (2) Assuming the residual thickness at point C is Hc and the intersection of points BC is Lx, the eroded thickness Hb and original thickness Hy at point C can be calculated respectively: Hb = Hy - Hc, Hy = Hb + H1*Lx.

[0013] (3) Due to the undulation of the stratum, the stratum thickness will change in the horizontal direction. If the above formula is used to continue the calculation along the survey line, an error will occur. In this case, a reference layer can be selected in the residual stratum to recalculate the thickness change rate.

[0014] (4) Let the reference layer thickness at point C be HC, the reference layer thickness at point D be HD, and the distance between points CD is M. Then the rate of change of thickness at point CD and its vicinity is Hm = (HD - HC) / M.

[0015] (5) Considering the inheritance of the same layer of sedimentation, the thickness change rate of the reference layer can be used to replace the thickness change rate of the entire formation, that is, Hm can be used instead of H1, and the calculation can be continued.

[0016] This method is independent of the number of tectonic movements and the amplitude of ups and downs in the basin. It is suitable not only for monocline layers, but also for arbitrarily undulating strata. It can be based on seismic data, has many control points, and is highly reliable. The method is simple, only requires thickness data, does not involve erosion time, and is highly operational. However, the calculation is limited to the same large structural layer and cannot cross large regional unconformity surfaces, otherwise the obtained stratum erosion amount will be inaccurate.

[0017] The third method is to use logging data to calculate the amount of formation erosion - sedimentation rate method

[0018] An unconformity represents a period of time during which a certain thickness of sediment was eroded. Therefore, this period of time actually consists of two parts: the time it took for that thickness to be deposited and the time it took for that thickness to be eroded. If the sedimentation rate of the eroded rock layer and the absolute age of the rock layers above and below the unconformity are known, the thickness of the eroded sediment layer can be calculated as follows:

[0019] (1) Sedimentation rate ratio method: Based on the high degree of inheritance and similarity of sedimentary characteristics, the erosion thickness is estimated by assuming that the sedimentation rate ratios of adjacent strata at different points are equal. Let the sedimentation rate ratio be P, the sedimentation thickness of the adjacent layer at point A be Ha, and the sedimentation time be Ta; the sedimentation time of the calculated layer be ta, and the residual thickness be hc. Then, the erosion thickness (h) of the calculated layer at point A is: h = (P × Ha × ta) / Ta - hc.

[0020] (2) Sedimentation rate trend method: In fact, the sedimentation rate of a stratum is not equal everywhere. Different geological environments have their own corresponding sedimentation rates. However, the lateral variation of the sedimentation rate is continuous, and the erosion thickness can be estimated based on this. Assuming the sedimentation rate at point A is h / t and the sedimentation rate at point B is zero, the sedimentation rate at point C can be interpolated to obtain the original sedimentation thickness. Then, the residual thickness is subtracted from this value to obtain the erosion thickness at point C.

[0021] This method is adaptable to diverse geological conditions, regardless of sedimentary lithology, whether later sedimentation exceeds the amount of erosion, or the number of unconformities within a basin. However, its implementation requires determining the relationship between sedimentation rates and those of the underlying strata. The absolute age of strata is difficult to determine, which can also lead to inaccurate results.

[0022] The fourth method uses well logging data to calculate the amount of formation erosion—vitrinite reflectance inversion. Ro is controlled by both thermal and burial history, and the recovery of burial history depends on the determination of the amount of formation erosion. Therefore, when other conditions are constant, Ro is a function of temperature and erosion. If the thermal history of the sample is known, the burial history can be inverted based on the chemical kinetic model of Ro, thereby determining the erosion thickness. In logarithmic coordinates, if the Ro profile line of the formation below the unconformity passes through the unconformity and is extended upward to a depth point where the Ro value equals the Ro of the overlying formation interface, the depth difference between this point and the unconformity is the amount of erosion (minimum erosion thickness). In the early stages of reburial of the eroded strata, the Ro of the strata below the unconformity surface does not change significantly, while the Ro of the newly deposited strata above the unconformity surface increases rapidly with increasing burial depth. After a certain period of time, if the reburial depth approaches or exceeds the original burial depth, the vitrinite reflectance profiles above and below the unconformity surface are close to being connected. Therefore, this method obtains the minimum erosion thickness, and sometimes it is even impossible to restore the erosion thickness.

[0023] In summary, most of the above methods directly use the denudation calculation results without exploring the accuracy of the denudation amount and whether it conforms to the actual situation. Although some methods have correction steps, they are not applicable to ultra-deep formations. For example, vitrinite does not exist in ultra-deep Precambrian formations (there are no higher plants), and solid asphalt equivalent reflectivity is often used as a substitute. Therefore, the accuracy of the final formation denudation degree is questionable.

[0024] In addition, the patent document with publication number CN106291695A also discloses a method for calculating the amount of stratum erosion, which includes: calibrating the well seismic depth based on well logging data and seismic data to determine the seismic layer position in the area to be calculated; determining the erosion stratum interface and the top and bottom interfaces of the underlying intact stratum in the area to be calculated; calculating the sedimentary thickness of the overlying layer based on the ratio of adjacent layer thicknesses and the thickness of the underlying layer; and if the calculated value is greater than the residual layer thickness of the overlying layer, the excess is the erosion thickness. This method combines seismic data and well logging data, and calculates the amount of stratum erosion based on the ratio of adjacent layer thicknesses according to geological sedimentary laws. However, this method uses the method of proportional recovery to calculate the difference to calculate the erosion thickness, which has the following obvious shortcomings:

[0025] (1) This method is only suitable for areas with a high degree of research or within the same large structural layer, and cannot cross large regional unconformities, resulting in its poor practicality.

[0026] (2) This method is only applicable to cases where the calculated thickness is greater than the residual thickness. If it is less than the residual thickness, it is considered to be uneroded. It does not take into account the influence of other geological effects such as compaction, resulting in the problem of insufficient accuracy. Summary of the Invention

[0027] The purpose of the present invention is to overcome the above-mentioned technical problems existing in the prior art, and provide a method for correcting the amount of stratum erosion using two-dimensional simulation. This method uses the influence of two-dimensional reservoir simulation and stratum burial evolution on the thermal evolution of source rocks to invert the stratum erosion thickness. By comparing the ground temperature, maturity and hydrocarbon generation differences of the same source rock layer in different regions during the geological history period, the difference in stratum erosion amount in different regions during the period is judged. Based on the two-dimensional reservoir evolution simulation, the amount of stratum erosion that conforms to the changes in structural morphology during each tectonic movement period is finally obtained more accurately, and there is no research area restriction, thereby effectively solving the technical problem that the prior art cannot accurately calculate the amount of stratum erosion.

[0028] To achieve the above object, the technical solution adopted by the present invention is as follows:

[0029] A method for correcting stratum erosion using two-dimensional simulation, characterized by comprising the following steps:

[0030] Step 1: Restore the stratum erosion thickness during the typical tectonic movement period when typical tectonic uplift events occurred in the study area;

[0031] Step 2: Based on the results of step 1, obtain a contour map of the erosion thickness of the top surface of the typical structure in the study area and the tectonic evolution process of the study area. Then, in combination with the tectonic evolution process, select at least two typical wells on the contour map of the erosion thickness and obtain the stratum erosion thickness of each typical well during the typical tectonic movement period; the typical structure top surface refers to the sedimentary top surface when the typical tectonic uplift event occurred;

[0032] Step 3: Based on the results of step 2, combined with the paleoheat flow value and source rock parameters of the study area, one-dimensional oil and gas accumulation simulation is performed on each typical well to obtain the source rock maturity evolution history and geothermal evolution history of each typical well;

[0033] Step 4: intercept a 2D seismic profile of a typical well and perform a 2D oil and gas accumulation simulation to obtain a 2D dynamic oil and gas accumulation evolution diagram of the intercepted profile;

[0034] Step 5: Set a virtual well in the two-dimensional dynamic oil and gas accumulation evolution process diagram, and perform one-dimensional oil and gas accumulation simulation on the virtual well. Then compare the one-dimensional oil and gas accumulation simulation results of the virtual well with the fluid inclusion analysis results of the actual target layer in the study area. If the comparison results are consistent, it is determined that the formation erosion thickness restored in step 1 is accurate; if the comparison results are inconsistent, it is determined that the formation erosion thickness restored in step 1 is inaccurate. Then, the formation erosion thickness is corrected according to the comparison results, and steps 2-5 are repeated based on the corrected formation erosion thickness until the accurate formation erosion thickness is obtained.

[0035] In step 1, the stratum erosion thickness during the typical tectonic movement period in the study area is recovered by the cross-section method based on the seismic surface map, well logging data, and the planar structural map of the top surface of the typical structure, and the sonic time difference method based on the sonic logging curve.

[0036] In step 1, a typical tectonic uplift event refers to an uplift event in which the target layer in the study area suffers significant erosion after deposition.

[0037] In step 2, the typical number of wells is 2-5.

[0038] In step 3, the source rock parameters include TOC parameters, kerogen type parameters, hydrogen index parameters obtained through actual experiments, and a hydrocarbon generation model selected based on the actual conditions of the study area.

[0039] In step 5, comparing the one-dimensional oil and gas accumulation simulation results of the virtual well with the fluid inclusion analysis results of the actual target layer in the study area means: first, obtaining the oil and gas filling time, oil and gas phase during oil and gas filling, and simulated formation temperature of the virtual well based on the one-dimensional oil and gas accumulation simulation results; obtaining the oil and gas filling time, oil and gas phase during oil and gas filling, and actual formation temperature of the actual target layer based on the fluid inclusion analysis results; then comparing the oil and gas filling time, oil and gas phase during oil and gas filling, and simulated formation temperature of the virtual well with the oil and gas filling time, oil and gas phase during oil and gas filling, and actual formation temperature of the actual target layer, respectively; if any comparison result does not match, it is determined that the formation erosion thickness is inaccurate.

[0040] The comparison sequence is: first compare the simulated formation temperature with the actual formation temperature, and then compare the oil and gas filling time and / or the oil and gas phase during the oil and gas filling.

[0041] In step 5, when the simulated formation temperature of the virtual well does not match the actual formation temperature of the actual target layer, the formation erosion thickness correction method is as follows: if the simulated formation temperature is greater than the actual formation temperature, it indicates that the simulated oil and gas evolution process is too fast and the formation erosion thickness restored in step 1 is too thin, then the formation erosion thickness is increased for correction; conversely, it indicates that the simulated oil and gas evolution process is too slow and the formation erosion thickness restored in step 1 is too thick, then the formation erosion thickness is reduced for correction.

[0042] The method for increasing or decreasing the erosion thickness is as follows: first, the geothermal gradient corresponding to the typical tectonic movement period is calculated based on the paleoheat flow value; then, the total erosion thickness to be increased or decreased is calculated based on the difference between the simulated formation temperature and the actual formation temperature and the geothermal gradient; finally, the total erosion thickness is proportionally distributed to the formation erosion thickness caused by the typical tectonic uplift event that occurred before the oil and gas injection time.

[0043] In step 5, the virtual well is a corresponding well that overlaps with any typical well in spatial position, or a well constructed in the 2D dynamic oil and gas accumulation evolution process map, or another adjacent well that passes through the 2D seismic profile of the typical well.

[0044] The advantages of adopting the present invention are:

[0045] 1. The method for correcting stratum erosion using two-dimensional simulation, as described herein, primarily comprises five steps. These specific steps utilize the influence of two-dimensional reservoir formation simulation and stratum burial evolution on source rock thermal evolution to invert stratum erosion thickness. By comparing the geotemperature, maturity, and hydrocarbon generation differences of the same source rock layer across different geological periods, the method determines differences in stratum erosion across different regions during that period. Based on two-dimensional reservoir formation evolution simulation, the method not only conforms to the laws of source rock burial evolution, but also intuitively reflects the true evolution of tectonic strata, minimizing the influence of other physical and chemical factors within the strata. Furthermore, the method utilizes fluid inclusion analysis results as a basis for comparison with one-dimensional evolution, thereby verifying the increased reliability of stratum erosion calculations. Ultimately, the method more accurately derives stratum erosion consistent with tectonic morphological changes during each tectonic movement period, effectively resolving the technical issue of prior art in accurately calculating stratum erosion.

[0046] In addition, the present invention utilizes a one-dimensional evolution pattern diagram of a virtual well to restore stratum evolution instead of proportional calculation. It has no research area restrictions and is not affected by other geological effects, so it has greater applicability.

[0047] 2. The present invention utilizes the aforementioned temperatures and times during oil and gas generation or phase transition periods for comparison, allowing for a greater number of fluid inclusions to be used, resulting in more pronounced variations in the one-dimensional simulation results, thus significantly improving the accuracy of the comparison. Furthermore, by increasing and decreasing the erosion thickness using a proportional distribution method, the impact of exceptional circumstances is minimized, resulting in an average result that most closely resembles the actual geological history.

[0048] 3. Through further detailed verification and correction, the present invention significantly improves the accuracy of the resulting stratum denudation thickness, making it more consistent with actual conditions. Generally speaking, when simulating one-dimensional and two-dimensional oil and gas accumulation, simulation software results more closely reflect the thermal evolution of the source rock and the phase evolution of the source rock and oil and gas phases within the reservoir. The specific distribution of ancient oil and gas reservoirs also depends on the distribution of reservoirs and traps. Therefore, through specific comparative verification and correction, the present invention can obtain a more accurate stratum denudation thickness.

[0049] 4. The present invention has outstanding economic value and can greatly save the drilling cost of oil and gas fields in understanding the distribution characteristics of deep oil and gas reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0050] Figure 1It is a flowchart of the present invention;

[0051] Figure 2 The plane contour map of erosion thickness obtained for the present invention;

[0052] Figure 3 A diagram of the structural evolution process obtained for the present invention;

[0053] Figure 4 The maturity evolution history and geothermal evolution history of the source rocks of each typical well in the present invention;

[0054] Figure 5 A two-dimensional seismic profile of a typical well taken for the present invention;

[0055] Figure 6 The two-dimensional dynamic oil and gas accumulation evolution process of the cross section taken in this invention Figure 1 ;

[0056] Figure 7 The two-dimensional dynamic oil and gas accumulation evolution process of the cross section taken in this invention Figure 2 ;

[0057] Figure 8 This is the fluid inclusion analysis result diagram of the actual target layer obtained by the present invention. DETAILED DESCRIPTION

[0058] Example 1

[0059] This embodiment discloses a method for correcting the amount of stratum erosion using two-dimensional simulation, such as Figure 1 As shown, it includes the following steps:

[0060] Step 1: Select the study area and use existing conventional techniques to restore the stratum erosion thickness during the typical tectonic movement period when typical tectonic uplift events occurred in the study area.

[0061] In this step, the typical tectonic uplift event refers to an uplift event in which the target layer in the study area undergoes significant erosion after deposition, such as the Tongwan Movement and the Caledonian Movement.

[0062] It should be noted that the thickness of strata eroded during typical tectonic periods in the study area was recovered using the cross-section method based on seismic maps, well logging data, and planar structural maps of typical structural tops, and the acoustic transit time method based on acoustic logging curves. This method of recovering stratum erosion thickness is conventional and will not be elaborated on here.

[0063] Step 2: Based on the results of step 1, obtain (draw) the erosion thickness plane contour map of the typical structural top surface of the study area and the structural evolution process of the study area. Among them, the typical structural top surface refers to the sedimentary top surface when the typical structural uplift event occurs. The obtained erosion thickness plane contour map and structural evolution process map are as follows: Figure 2 、 3 As shown. Then, based on the tectonic evolution process, select at least two representative wells on the erosion thickness contour map. The locations of the representative wells should be as close as possible to those of key exploration wells in actual operations. The number of representative wells can range from 2 to 5, but 3 is preferred. After selecting the representative wells, obtain the stratum erosion thickness for each representative well during the typical tectonic movement period.

[0064] Step 3: Based on the results of step 2, the paleo-heat flow value and source rock parameters of the study area are combined to perform one-dimensional oil and gas accumulation simulation on each typical well. After the simulation is completed, the following results are obtained: Figure 4 The source rock maturity evolution history and geothermal evolution history of each typical well are shown.

[0065] The source rock parameters in this step include TOC parameters, kerogen type parameters, hydrogen index parameters obtained through actual experiments, and hydrocarbon generation models selected based on the actual conditions of the study area, all of which are existing research results.

[0066] Step 4: If Figure 5 As shown in the figure, a 2D seismic profile of a typical well was intercepted and a 2D oil and gas accumulation simulation was performed. After the simulation, the following is obtained: Figure 6 、 7 The two-dimensional dynamic oil and gas accumulation evolution process of the cross-section shown.

[0067] Step 5: Set a virtual well in the 2D dynamic oil and gas accumulation evolution map and perform 1D oil and gas accumulation simulation on the virtual well. A virtual well is a well that spatially overlaps with a typical well, or a well constructed in the 2D dynamic oil and gas accumulation evolution map, or an adjacent well that passes through the 2D seismic profile of the typical well. The number of virtual wells is typically one, but multiple can be used depending on actual needs.

[0068] Then, the fluid inclusion analysis results of the actual target layer in the study area are obtained. Figure 8 As shown in FIG, the one-dimensional oil and gas accumulation simulation results of the virtual well are compared with the fluid inclusion analysis results of the actual target layer in the study area. If the comparison results are consistent, the formation erosion thickness restored by step 1 is determined to be accurate; if the comparison results are inconsistent, the formation erosion thickness restored by step 1 is determined to be inaccurate, and then the formation erosion thickness is corrected according to the comparison results, and steps 2-5 are repeated based on the corrected formation erosion thickness until the accurate formation erosion thickness is obtained.

[0069] The criterion for whether the match is correct is whether the ground temperature at a certain period in the one-dimensional oil and gas accumulation simulation results of the virtual well is roughly the same as the formation temperature of the fluid inclusions at the corresponding time in the existing research results.

[0070] It should be noted that this embodiment does not limit the parameters that need to be compared between the one-dimensional oil and gas accumulation simulation results of the virtual well and the fluid inclusion analysis results of the actual target layer in the study area. The specific parameters can be selected and set according to actual needs, so as to obtain the accurate formation erosion thickness.

[0071] In summary, after adopting the above-mentioned specific steps, this embodiment can more accurately obtain the amount of stratum erosion that conforms to the changes in structural morphology during each tectonic movement period without being restricted by the study area and affected by other geological effects, thereby effectively solving the technical problem that the existing technology cannot accurately calculate the amount of stratum erosion.

[0072] Example 2

[0073] This embodiment discloses a method for correcting the amount of stratum erosion using two-dimensional simulation based on embodiment 1, such as Figure 1 As shown, it includes the following steps:

[0074] Step 1: Select the study area and restore the stratum erosion thickness during the typical tectonic movement period when a typical tectonic uplift event occurred in the study area.

[0075] Step 2: Based on the results of step 1, obtain (draw) the erosion thickness plane contour map of the typical structural top surface of the study area and the structural evolution process of the study area. Among them, the typical structural top surface refers to the sedimentary top surface when the typical structural uplift event occurs. The obtained erosion thickness plane contour map and structural evolution process map are as follows: Figure 2 、 3 As shown. Then, based on the tectonic evolution process, select at least two representative wells on the erosion thickness contour map. The locations of the representative wells should be as close as possible to those of key exploration wells in actual operations. The number of representative wells can range from 2 to 5, but 3 is preferred. After selecting the representative wells, obtain the stratum erosion thickness for each representative well during the typical tectonic movement period.

[0076] Step 3: Based on the results of step 2, the paleo-heat flow value and source rock parameters of the study area are combined to perform one-dimensional oil and gas accumulation simulation on each typical well. After the simulation is completed, the following results are obtained: Figure 4 The source rock maturity evolution history and geothermal evolution history of each typical well are shown.

[0077] Step 4: If Figure 5 As shown in the figure, a 2D seismic profile of a typical well was intercepted and a 2D oil and gas accumulation simulation was performed. After the simulation, the following is obtained: Figure 6 、 7The two-dimensional dynamic oil and gas accumulation evolution process of the cross-section shown.

[0078] Step 5: Set a virtual well in the two-dimensional dynamic oil and gas accumulation evolution process map, and perform one-dimensional oil and gas accumulation simulation on the virtual well. Among them, the virtual well is a corresponding well that overlaps with any typical well in spatial position, or a well constructed in the two-dimensional dynamic oil and gas accumulation evolution process map, or an adjacent well of other two-dimensional seismic profiles of typical wells. The number of virtual wells is usually one, but it can also be multiple according to actual needs. Then obtain the fluid inclusion analysis results of the actual target layer in the study area. The obtained fluid inclusion analysis results of the actual target layer are as follows: Figure 8 As shown in FIG, the one-dimensional oil and gas accumulation simulation results of the virtual well are compared with the fluid inclusion analysis results of the actual target layer in the study area. If the comparison results are consistent, the formation erosion thickness restored by step 1 is determined to be accurate; if the comparison results are inconsistent, the formation erosion thickness restored by step 1 is determined to be inaccurate, and then the formation erosion thickness is corrected according to the comparison results, and steps 2-5 are repeated based on the corrected formation erosion thickness until the accurate formation erosion thickness is obtained.

[0079] This embodiment further defines the comparison in step 5. Preferably, the comparison of the one-dimensional oil and gas accumulation simulation results of the virtual well with the fluid inclusion analysis results of the actual target layer in the study area refers to:

[0080] First, the oil and gas injection time, oil and gas phase state during injection, and simulated formation temperature of the virtual well are obtained based on the results of one-dimensional oil and gas accumulation simulation. The oil and gas injection time, oil and gas phase state during injection, and actual formation temperature of the actual target layer are obtained based on the results of fluid inclusion analysis. The oil and gas injection time, oil and gas phase state during injection, and simulated formation temperature of the virtual well are then compared with the oil and gas injection time, oil and gas phase state during injection, and actual formation temperature of the actual target layer, respectively. Because formation temperature and oil and gas evolution processes correspond to each other within a specific study area, the preferred comparison order is: first compare the simulated formation temperature with the actual formation temperature, then compare the oil and gas injection time and / or oil and gas phase state during injection. If any of the above comparison results do not match, the formation erosion thickness is determined to be inaccurate.

[0081] Since this embodiment uses the temperature and time of the oil and gas generation or phase transformation period for comparison, a larger number of fluid inclusions can be used, so the changes in the one-dimensional simulation results are more obvious, thereby greatly improving the accuracy of the comparison effect.

[0082] Example 3

[0083] This embodiment discloses a method for correcting the amount of stratum erosion using two-dimensional simulation based on embodiment 1, such as Figure 1 As shown, it includes the following steps:

[0084] Step 1: Select the study area and restore the stratum erosion thickness during the typical tectonic movement period when a typical tectonic uplift event occurred in the study area.

[0085] Step 2: Based on the results of step 1, obtain (draw) the erosion thickness plane contour map of the typical structural top surface of the study area and the structural evolution process of the study area. Among them, the typical structural top surface refers to the sedimentary top surface when the typical structural uplift event occurs. The obtained erosion thickness plane contour map and structural evolution process map are as follows: Figure 2 、 3 As shown. Then, based on the tectonic evolution process, select at least two representative wells on the erosion thickness contour map. The locations of the representative wells should be as close as possible to those of key exploration wells in actual operations. The number of representative wells can range from 2 to 5, but 3 is preferred. After selecting the representative wells, obtain the stratum erosion thickness for each representative well during the typical tectonic movement period.

[0086] Step 3: Based on the results of step 2, the paleo-heat flow value and source rock parameters of the study area are combined to perform one-dimensional oil and gas accumulation simulation on each typical well. After the simulation is completed, the following results are obtained: Figure 4 The source rock maturity evolution history and geothermal evolution history of each typical well are shown.

[0087] Step 4: If Figure 5 As shown in the figure, a 2D seismic profile of a typical well was intercepted and a 2D oil and gas accumulation simulation was performed. After the simulation, the following is obtained: Figure 6 、 7 The two-dimensional dynamic oil and gas accumulation evolution process of the cross-section shown.

[0088] Step 5: Set a virtual well in the two-dimensional dynamic oil and gas accumulation evolution process map, and perform one-dimensional oil and gas accumulation simulation on the virtual well. Among them, the virtual well is a corresponding well that overlaps with any typical well in spatial position, or a well constructed in the two-dimensional dynamic oil and gas accumulation evolution process map, or an adjacent well of other two-dimensional seismic profiles of typical wells. The number of virtual wells is usually one, but it can also be multiple according to actual needs. Then obtain the fluid inclusion analysis results of the actual target layer in the study area. The obtained fluid inclusion analysis results of the actual target layer are as follows: Figure 8 As shown in FIG, the one-dimensional oil and gas accumulation simulation results of the virtual well are compared with the fluid inclusion analysis results of the actual target layer in the study area. If the comparison results are consistent, the formation erosion thickness restored by step 1 is determined to be accurate; if the comparison results are inconsistent, the formation erosion thickness restored by step 1 is determined to be inaccurate, and then the formation erosion thickness is corrected according to the comparison results, and steps 2-5 are repeated based on the corrected formation erosion thickness until the accurate formation erosion thickness is obtained.

[0089] This embodiment further limits the comparison method of step 5. Preferably, the comparison of the one-dimensional oil and gas accumulation simulation results of the virtual well with the fluid inclusion analysis results of the actual target layer in the study area refers to:

[0090] First, the oil and gas injection time, oil and gas phase state during injection, and simulated formation temperature of the virtual well are obtained based on the results of one-dimensional oil and gas accumulation simulation. The oil and gas injection time, oil and gas phase state during injection, and actual formation temperature of the actual target layer are obtained based on the results of fluid inclusion analysis. The oil and gas injection time, oil and gas phase state during injection, and simulated formation temperature of the virtual well are then compared with the oil and gas injection time, oil and gas phase state during injection, and actual formation temperature of the actual target layer, respectively. Because formation temperature and oil and gas evolution processes correspond to each other within a specific study area, the preferred comparison order is: first compare the simulated formation temperature with the actual formation temperature, then compare the oil and gas injection time and / or oil and gas phase state during injection. If any of the above comparison results do not match, the formation erosion thickness is determined to be inaccurate.

[0091] This embodiment further limits the correction process of step 5. Preferably, when the simulated formation temperature of the virtual well does not match the actual formation temperature of the actual target layer, the formation erosion thickness correction method is: if the simulated formation temperature is greater than the actual formation temperature, it indicates that the simulated oil and gas evolution process is too fast and the formation erosion thickness restored by step 1 is too thin, then the formation erosion thickness is increased for correction; conversely, it indicates that the simulated oil and gas evolution process is too slow and the formation erosion thickness restored by step 1 is too thick, then the formation erosion thickness is reduced for correction.

[0092] Furthermore, the method for increasing or decreasing the erosion thickness is: first, calculate the geothermal gradient corresponding to the typical tectonic movement period based on the paleoheat flow value; then calculate the total erosion thickness to be increased or decreased based on the difference between the simulated formation temperature and the actual formation temperature and the geothermal gradient; finally, distribute the total erosion thickness in proportion to the formation erosion thickness caused by the typical tectonic uplift event that occurred before the oil and gas injection time.

[0093] Since this embodiment adopts the proportional distribution method to increase or decrease the erosion thickness, it can minimize the impact of special circumstances and achieve the result that is closest to the actual geological history under average conditions.

[0094] Example 4

[0095] This embodiment is based on the embodiment 3, and the present invention is verified in the northern slope area of ​​the central Sichuan region as the research area. Figure 1 As shown, it includes the following steps:

[0096] Step 1: Based on the previous work on restoration of erosion thickness, the stratum erosion thickness during the main tectonic activity period in the north slope area was restored using the image section method and the acoustic time difference method.

[0097] Episode II of the Tongwan Movement was the most intense erosion, reaching a maximum thickness of 175 m. During the Caledonian Movement, strata between the Lower Cambrian and Permian systems were denuded, with maximum denudation thickness reaching 1,600 m, decreasing gradually from the Gaomo area to the north slope. During the Hercynian Movement, strata at the top of the Permian Maokou Formation were denuded, with thicknesses ranging from 140 to 200 m, with the thickness of denudation slightly less on the north slope than in the Gaomo area. The Indosinian Movement caused denudation of strata between the Middle and Upper Triassic systems, with thicknesses ranging from 0 to 300 m, decreasing gradually from the Gaomo area to the north slope. Cumulative erosion from the Yanshan-Himalayan Movement (Jurassic) to the present day has been cumulative, with cumulative denudation ranging from 2,000 to 4,600 m in the Gaomo area and a relatively smaller 1,600 to 2,800 m on the north slope.

[0098] Step 2: Based on the results of step 1, obtain the erosion thickness contour map of the top surface of the typical structure in the northern slope area of ​​the central Sichuan region and the structural evolution process of the study area. Then, combined with the structural evolution process, select three typical wells ( Figure 2 The three black dots in the figure represent three typical wells, and the stratum erosion thickness of each typical well during the typical tectonic movement period was obtained.

[0099] Step 3: Combined with the structural evolution process in step 2, the parameters required for one-dimensional oil and gas accumulation simulation and two-dimensional oil and gas accumulation simulation evolution are set based on the single well logging data and seismic profile data. Then, one-dimensional oil and gas accumulation simulation is performed on each typical well, and the following is obtained: Figure 4 The source rock maturity evolution history and geothermal evolution history of each typical well are shown.

[0100] Step 4: If Figure 5 As shown in the figure, the simulation software was used to intercept the 2D seismic profile of a typical well and perform 2D oil and gas accumulation simulation, and the results are as follows: Figure 6 、 7 The two-dimensional dynamic oil and gas accumulation evolution process diagram of the selected section in the northern slope area is shown.

[0101] The section captured in this project is a large-scale structural section from Well Detan 1, Zhongjiang 2, Zhongshen 102, Zhongshen 103, Pengtan 103, Pengtan 1, Pengtan 101, and Moxi 8 in the Taihe gas-bearing area of ​​central Sichuan and the Gao-Mo area. The section passes through the Zhongjiang, Penglai, and Gao-Mo areas, with a northwest-southeast trend. From Well Detan 1 to Well Moxi 8, the sedimentary facies of the Deng 2 Member platform-marginal mound-shoal, the Deng 4 Member platform-marginal mound-shoal, and the intra-platform mound-shoal are sequentially traversed. Based on this seismic section, a 2D oil and gas accumulation simulation was conducted.

[0102] Step 5: Set a virtual well in the cross section in step 4, for example, Zhongjiang 2 well, and then compare the one-dimensional oil and gas accumulation simulation results of Zhongjiang 2 well with the Figure 8The results of fluid inclusion analysis are compared with those shown in the figure, and the reliability of the fluid inclusion analysis results is confirmed by the comparison results.

[0103] Step 5-1: Based on the single well logging data of Zhongjiang 2 Well and combined with the actual geological conditions of the study area, a one-dimensional oil and gas accumulation simulation was conducted on Zhongjiang 2 Well to obtain the maturity evolution history of its source rock and geothermal evolution history.

[0104] Step 5-2: Based on the results of step 5-1, focus on extracting the maturity evolution and geothermal evolution history of the source rock of the target layer.

[0105] Step 5-3: Compare the fluid inclusion analysis results, observe the source rock maturity and geothermal temperature of the target layer of Well Zhongjiang 2 during the main hydrocarbon accumulation period, and determine whether the one-dimensional oil and gas accumulation simulation results are consistent with the actual geological conditions reflected by the inclusions.

[0106] Specifically, three types of hydrocarbon inclusions were discovered in the Dengying Formation oil and gas reservoirs, clustered in dolomite and quartz. Type I hydrocarbon inclusions are primarily single-phase (all liquid, oil) inclusions. Type II hydrocarbon inclusions are primarily gas-liquid two-phase aqueous fluid inclusions. Both types of inclusions are distributed in dolomite. In contrast, Type III hydrocarbon inclusions, which are single-phase gas inclusions, were found in quartz. Furthermore, the homogenization temperatures of the gas-liquid two-phase brine inclusions accompanying these three hydrocarbon inclusions were studied. The homogenization temperatures show a gradually increasing trend in the central Sichuan Basin, from Type I hydrocarbon inclusions (homogenization temperature: 130-140°C) to Type II (homogenization temperature: 170-190°C) and Type III (homogenization temperature: 210-220°C) brine inclusions. Fluid inclusion studies indicate three stages of reservoir formation in the Dengying Formation oil and gas reservoir in the Penglai block. The first two stages were dominated by liquid hydrocarbons, while the third stage was dominated by dry gas.

[0107] Combined with previous analysis of reservoir formation using fluid inclusions, the reservoir formation periods in this study can be divided into four main stages:

[0108] (1) Initial oil generation stage: Late Caledonian Movement, after the end of the Silurian Period, about 419 Ma ago.

[0109] (2) Large-scale oil generation stage: Late Hercynian Movement to Early Indosinian Movement, that is, from the late Permian to the early Triassic, about 251 Ma ago.

[0110] (3) Initial oil-gas cracking stage: Late Triassic to Early Jurassic, about 200 Ma ago.

[0111] (4) Stage of large-scale cracking of crude oil: Late Yanshan Movement, Middle-Late Jurassic, about 163 Ma ago.

[0112] Step 5-4: If the source rock maturity and geotemperature in the one-dimensional hydrocarbon accumulation simulation results meet the corresponding hydrocarbon generation and accumulation criteria for the source rock or crude oil cracking, the recovered stratum erosion during the tectonic period is consistent with the geological history. If the source rock maturity and formation temperature of the target layer in the one-dimensional simulation results do not meet the hydrocarbon generation and accumulation conditions reflected by the inclusions, the recovered stratum erosion is incorrect. This is because according to the principle of one-dimensional simulation inversion: if the recovered stratum erosion is slightly smaller, it means that the target layer was not buried deep enough before tectonic movement, and the formation temperature was difficult to meet the requirements for hydrocarbon generation or conversion; if the recovered stratum erosion is slightly larger, the opposite is true.

[0113] Step 5-5: After determining each tectonic movement period one by one, the tectonic movement with a smaller erosion thickness recovery result shall be appropriately increased in erosion thickness according to the geothermal gradient, hydrocarbon generation temperature of source rock and cracking temperature of crude oil; the tectonic movement with a larger erosion thickness recovery result shall be appropriately reduced in stratum erosion thickness.

[0114] Based on this, for Zhongjiang 2 Well:

[0115] a. Episode II of Tongwan Movement: 174m of erosion. The one-dimensional simulation results are later than the accumulation period shown by the inclusions, indicating that the calculated results are too small. The erosion thickness is adjusted to 250m, and the results show that it is consistent with the accumulation period of the inclusions.

[0116] b. Caledonian Movement: 1520m of erosion. The one-dimensional simulation results are later than the accumulation period shown by the inclusions, indicating that the calculated results are too small. The erosion thickness is adjusted to 2500m, and the results show that it is consistent with the accumulation period of the inclusions.

[0117] c. Hercynian Movement: erosion of 130m, consistent with the accumulation period shown by fluid inclusions.

[0118] d. Indosinian Movement: erosion of 10m, consistent with the accumulation period shown by fluid inclusions.

[0119] e. Himalayan movement: erosion of 2500m, consistent with the accumulation period shown by fluid inclusions.

[0120] Step 5-6: Reset the one-dimensional simulation parameters of Well Zhongjiang 2 based on the stratum denudation thickness of each tectonic movement period obtained after adjustment in step 5-5, and perform one-dimensional oil and gas accumulation simulation again.

[0121] Step 5-7: Compare the adjusted source rock maturity and geothermal history from Step 5-6 with the fluid inclusion analysis results to determine the accuracy of the 1D simulation results. If the results match, the modified stratum denudation thickness is consistent with the geological history. If not, repeat the above steps until accurate results are obtained.

[0122] The above description is only a specific embodiment of the present invention. Any feature disclosed in this specification, unless otherwise stated, can be replaced by other equivalent or alternative features with similar purposes; all disclosed features, or all steps in the methods or processes, except for mutually exclusive features and / or steps, can be combined in any way.

Claims

1. A method for correcting stratum erosion using two-dimensional simulation, characterized in that The following steps are involved: Step 1: Restore the stratum erosion thickness during the typical tectonic movement period when typical tectonic uplift events occurred in the study area; Step 2: Based on the results of step 1, obtain a contour map of the erosion thickness of the top surface of the typical structure in the study area and the tectonic evolution process of the study area. Then, in combination with the tectonic evolution process, select at least two typical wells on the contour map of the erosion thickness and obtain the stratum erosion thickness of each typical well during the typical tectonic movement period; the typical structure top surface refers to the sedimentary top surface when the typical tectonic uplift event occurred; Step 3: Based on the results of step 2, combined with the paleoheat flow value and source rock parameters of the study area, one-dimensional oil and gas accumulation simulation is performed on each typical well to obtain the source rock maturity evolution history and geothermal evolution history of each typical well; Step 4: intercept a 2D seismic profile of a typical well and perform a 2D oil and gas accumulation simulation to obtain a 2D dynamic oil and gas accumulation evolution diagram of the intercepted profile; Step 5: Set a virtual well in the two-dimensional dynamic oil and gas accumulation evolution process diagram, and perform one-dimensional oil and gas accumulation simulation on the virtual well. Then compare the one-dimensional oil and gas accumulation simulation results of the virtual well with the fluid inclusion analysis results of the actual target layer in the study area. If the comparison results are consistent, it is determined that the formation erosion thickness restored in step 1 is accurate; if the comparison results are inconsistent, it is determined that the formation erosion thickness restored in step 1 is inaccurate. Then, the formation erosion thickness is corrected according to the comparison results, and steps 2-5 are repeated based on the corrected formation erosion thickness until the accurate formation erosion thickness is obtained.

2. The method for correcting stratum erosion using two-dimensional simulation according to claim 1, characterized in that: In step 5, comparing the one-dimensional oil and gas accumulation simulation results of the virtual well with the fluid inclusion analysis results of the actual target layer in the study area means: first, obtaining the oil and gas filling time, oil and gas phase during oil and gas filling, and simulated formation temperature of the virtual well based on the one-dimensional oil and gas accumulation simulation results; obtaining the oil and gas filling time, oil and gas phase during oil and gas filling, and actual formation temperature of the actual target layer based on the fluid inclusion analysis results; then comparing the oil and gas filling time, oil and gas phase during oil and gas filling, and simulated formation temperature of the virtual well with the oil and gas filling time, oil and gas phase during oil and gas filling, and actual formation temperature of the actual target layer, respectively; if any comparison result does not match, it is determined that the formation erosion thickness is inaccurate.

3. The method for correcting stratum erosion using two-dimensional simulation according to claim 2, characterized in that: The comparison sequence is: first compare the simulated formation temperature with the actual formation temperature, and then compare the oil and gas filling time and / or the oil and gas phase during the oil and gas filling.

4. The method for correcting stratum erosion using two-dimensional simulation according to claim 2 or 3, characterized in that: In step 5, when the simulated formation temperature of the virtual well does not match the actual formation temperature of the actual target layer, the formation erosion thickness correction method is as follows: if the simulated formation temperature is greater than the actual formation temperature, it indicates that the simulated oil and gas evolution process is too fast and the formation erosion thickness restored in step 1 is too thin, then the formation erosion thickness is increased for correction; On the contrary, it indicates that the simulated oil and gas evolution process is too slow and the formation erosion thickness restored in step 1 is too thick, so the formation erosion thickness should be reduced for correction.

5. The method for correcting stratum erosion using two-dimensional simulation according to claim 4, characterized in that: The method for increasing or decreasing the erosion thickness is as follows: first, calculate the geothermal gradient corresponding to the typical tectonic movement period based on the paleoheat flow value; then calculate the total erosion thickness to be increased or decreased based on the difference between the simulated formation temperature and the actual formation temperature and the geothermal gradient; finally, distribute the total erosion thickness in proportion to the stratum erosion thickness caused by the typical tectonic uplift event that occurred before the oil and gas injection time.

6. The method for correcting stratum erosion using two-dimensional simulation according to claim 1, characterized in that: In step 5, the virtual well is a corresponding well that overlaps with any typical well in spatial position, or a well constructed in the 2D dynamic oil and gas accumulation evolution process map, or another adjacent well that passes through the 2D seismic profile of the typical well.

7. The method for correcting stratum erosion using two-dimensional simulation according to claim 1, characterized in that: In step 1, the stratum erosion thickness during the typical tectonic movement period in the study area is recovered by the cross-section method based on the seismic surface map, well logging data, and the planar structural map of the top surface of the typical structure, and the sonic time difference method based on the sonic logging curve.

8. The method for correcting stratum erosion using two-dimensional simulation according to claim 1, characterized in that: In step 1, a typical tectonic uplift event refers to an uplift event in which the target layer in the study area suffers significant erosion after deposition.

9. The method for correcting stratum erosion using two-dimensional simulation according to claim 1, characterized in that: In step 2, the typical number of wells is 2-5.

10. The method for correcting stratum erosion using two-dimensional simulation according to claim 1, characterized in that: In step 3, the source rock parameters include TOC parameters, kerogen type parameters, hydrogen index parameters obtained through actual experiments, and a hydrocarbon generation model selected based on the actual conditions of the study area.

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