Method for identifying paleo-reservoir scale of carbonate reservoir based on combined abundance of asphalt inclusion

Abstract

The application belongs to the field of petroleum geology, and specifically discloses a method for identifying the scale of a paleo-reservoir of a carbonate rock reservoir based on the combined abundance of asphalt inclusion. The application collects a carbonate rock core in which dissolution pores and holes are developed and prepares a fluid inclusion slice; the filling mineral petrological characteristics and the generational growth relationship are determined by using a polarizing microscope and a cathodoluminescence technology; microfacies observation is carried out on the fluid inclusion combination as a unit, methane inclusions are identified in situ by using a laser Raman spectrum, and the methane saturation of a fluid system is identified; solid asphalt is identified in situ by using a laser Raman spectrum, and the thermal cracking cause of a paleo-reservoir is established; the number of solid-asphalt-containing fluid inclusion combinations and the total number of fluid inclusion combinations are counted, the asphalt-containing fluid inclusion combination abundance ABIA is calculated, the original charging scale of the paleo-reservoir is determined in combination with the current natural gas production, and the application effectively eliminates the interference of macroscopic reservoir asphalt heterogeneity, and provides quantitative support for the exploration and deployment of high-quality zones.

Description

Technical Field

[0001] This invention belongs to the field of petroleum geology, specifically relating to a method for identifying the scale of paleooil reservoirs in carbonate rocks based on the abundance of bituminous inclusion assemblages. Background Technology

[0002] Reservoir bitumen consists of solid hydrocarbon residues that fill the pores and fractures of reservoir rocks during the migration, accumulation, and subsequent alteration of petroleum. It is typically formed from crude oil from ancient reservoirs through high-temperature thermal cracking, gas de-asphalting, or biodegradation, and contains a wealth of geological information related to the evolutionary history of hydrocarbon accumulation. The original scale of petroleum accumulation during geological history directly determines not only the resource volume of the natural gas reservoir formed by subsequent cracking but also controls the development and distribution characteristics of solid bitumen within the reservoir. However, for reservoirs like carbonate rocks, which exhibit complex diagenesis and highly heterogeneous reservoir spaces, the spatial occurrence and abundance of solid bitumen are highly variable. After intense tectonic movements or subsequent fluid alteration, some reservoir bitumen may be destroyed, transported, or undergo secondary adjustments. Therefore, relying solely on macroscopic or microscopic reservoir solid bitumen residues cannot objectively and comprehensively characterize the original paleo-oil reservoir scale of the entire reservoir.

[0003] To accurately assess the scale of ancient carbonate reservoirs, it is essential to find crucial evidence that records the fluid charging history in situ during geological periods. Fluid inclusions, as natural micro-geological samples that capture and preserve original fluid information, possess irreplaceable advantages in diagenesis, mineralization, basin fluid evolution, and hydrocarbon migration identification. Currently, domestic and international scholars primarily use the Grains with Oil Inclusions (GOI) technique to characterize the charging scale of ancient reservoirs. However, the GOI technique mainly relies on the fluorescence effect of liquid hydrocarbon inclusions at the time of capture. For ancient reservoirs with high evolutionary levels (such as deep to ultra-deep carbonate rocks) or those that have undergone strong fracturing and alteration, most of the original liquid hydrocarbon inclusions have been transformed into non-fluorescent or weakly fluorescent bitumen or gaseous hydrocarbon inclusions, rendering this technique ineffective. Currently, for such highly evolved and strongly altered ancient carbonate reservoirs, the industry lacks a characterization method that can effectively eliminate post-alteration interference and accurately identify the relative scale and distribution range of ancient reservoirs. Therefore, this invention proposes a method for identifying the paleooil reservoir size of carbonate reservoirs based on the abundance of bituminous inclusion assemblages. This method establishes an effective identification and abundance evaluation system for bituminous inclusion assemblages during high-temperature evolution stages by statistically analyzing the abundance of bituminous inclusion assemblages in different occurrence states of reservoir minerals. This system has significant application value for studying the gas formation mechanism of deep-to-ultra-deep carbonate reservoirs, reconstructing paleooil-water interfaces, and evaluating the resource potential of natural gas reservoirs. Summary of the Invention

[0004] This invention provides a method for identifying the size of paleo-oil reservoirs in carbonate rocks based on the abundance of bituminous inclusions. It aims to solve the technical problem that the original charging scale of paleo-oil reservoirs in deep to ultra-deep carbonate rocks with high evolution and strong alteration cannot be accurately characterized due to the strong heterogeneity of solid bituminous distribution and the failure of traditional GOI technology. This method has the advantages of objective evaluation indicators, less interference from later alteration, and accurate and efficient identification of paleo-oil reservoir size.

[0005] To achieve the above objectives, the present invention adopts the following technical solution:

[0006] S1. Collect core samples from deep to ultra-deep carbonate natural gas reservoirs in the target strata, select core segments with dissolution cavities, and take samples at the locations where the dissolution cavities are developed to prepare double-sided polished fluid inclusion thin sections.

[0007] S2. Using polarized light microscopy and cathodoluminescence technology, the petrological characteristics of the filling minerals in the dissolution cavities of the fluid inclusion sheet are analyzed to clarify the mineral types, crystal morphology and generational growth relationships of the filling minerals, and to establish the time series of fluid capture.

[0008] S3. Using fluid inclusion assemblages as the basic analytical unit, conduct detailed micro-lithographic observations of the fluid inclusions trapped inside the filling minerals to determine the phase type (gas phase, liquid phase, and solid phase) and composition of each individual inclusion within the assemblages at room temperature. Use laser Raman spectroscopy to perform in-situ non-destructive identification of the gas phase components in the gas-liquid two-phase inclusions and the components of the single-phase inclusions, identify single-phase methane inclusions and gas-liquid two-phase methane-containing inclusions, and determine whether the fluid inclusion assemblages were captured as a methane supersaturated fluid system or a methane unsaturated fluid system.

[0009] If the gas-liquid ratio of inclusions within the same fluid inclusion assembly is significantly inconsistent (non-uniform capture), and it contains both single-phase methane inclusions and two-phase methane-containing inclusions, then the fluid inclusion assembly is identified as a methane-supersaturated fluid system during capture. If the same fluid inclusion assembly contains only two-phase methane-containing inclusions, and the gas-liquid ratio of each inclusion is basically consistent (uniform capture), then the fluid inclusion assembly is identified as a methane-unsaturated fluid system during capture.

[0010] S4. Use laser Raman spectroscopy to identify the solid phase material in the fluid inclusion assemblies of the above two types of fluid systems in situ, and determine whether solid bitumen is contained inside the inclusions: if a fluid inclusion assemblies of methane-rich (containing) inclusions and solid bitumen-containing inclusions are observed in the filling minerals, it is determined that the fluid captured in this period is of the origin of ancient oil reservoir crude oil thermal cracking, and the solid bitumen-containing inclusions are effective indicators for evaluating the scale of ancient oil reservoirs.

[0011] S5. For the same type or generation of filling minerals in the dissolved cavities, count the number N of effective fluid inclusion combinations containing solid bitumen, as confirmed by laser Raman spectroscopy. bitumen And the total number of fluid inclusion combinations N analyzed in the mineral. total The abundance of bituminous fluid inclusion assemblages (ABIA) is calculated using the following formula:

[0012]

[0013] S6. Compare the abundance differences of the combinations in different structural locations or zones within the same geological stratum, and verify them in conjunction with the current natural gas production characteristics and production data of the corresponding regions, thereby identifying and comparing the original charging scale of ancient oil reservoirs in different zones.

[0014] The present invention has the following beneficial effects:

[0015] (1) This method can identify the scale of ancient reservoirs by establishing a combined abundance model. This not only effectively avoids the cumbersome, costly and easily contaminated multi-element geochemical testing of reservoir solid bitumen in conventional large-scale analysis, but also utilizes the in-situ sealing of the inclusion system to eliminate the heterogeneous interferences such as macro-bitumen damage and transportation caused by strong tectonic fluid modification in the later stage.

[0016] (2) This invention overcomes the limitation of traditional oil inclusion particle index (GOI) technology, which is only applicable to low- to medium-evolution liquid hydrocarbon inclusions. For deep to ultra-deep carbonate reservoirs with high thermal evolution and strong fracturing, a charging scale identification system based on the combination of no / weak fluorescent bitumen inclusions is established. This provides quantitative support for the resource potential evaluation and high-quality zone exploration deployment of deep carbonate fracturing gas reservoirs. Attached Figure Description

[0017] Figure 1 This is a flowchart illustrating a method for identifying the size of paleooil reservoirs in carbonate rocks based on the abundance of bituminous inclusion assemblages provided by the present invention.

[0018] Figure 2 Photographs of Longwangmiao Formation carbonate rock core samples containing dissolution cavities from different work areas selected for this invention;

[0019] Figure 3 Microscopic petrological characteristics of minerals filling dissolution cavities in reservoirs, based on microscopic observation and cathodoluminescence analysis;

[0020] Figure 4It includes methane-rich (containing) fluid inclusion assemblages and fluid inclusion assemblages containing methane and solid bitumen inclusions.

[0021] Figure 5 This is a graph showing the relationship between the abundance parameters of the asphalt-containing fluid inclusion assemblages used in this invention and the daily natural gas production of a single well in the work area. Detailed Implementation

[0022] To more clearly present the objectives, technical solutions, and advantages of this application, the following will provide a detailed explanation of the technical solutions using specific implementation examples. It is important to emphasize that the embodiments listed herein are merely illustrative and exemplary, and do not represent a comprehensive coverage of all possible technical solutions. All other embodiments obtained by those skilled in the art based on the embodiments in this specification without inventive effort are within the scope of protection of this application.

[0023] Figure 1 This is a schematic flowchart illustrating a method for identifying the size of paleooil reservoirs in carbonate rocks based on the abundance of bituminous inclusion assemblages provided by this invention. In a specific embodiment, the method includes the following steps:

[0024] S1. Sample Collection and Thin Section Preparation of Deep-Ultra-Deep Carbonate Natural Gas Reservoirs Containing Dissolution Voids. Core samples were collected from deep-ultra-deep carbonate natural gas reservoirs in the target stratigraphic level. Specifically, core samples from multiple wells in the Cambrian Longwangmiao Formation in three work areas of the Sichuan Basin were used as the research object. Cores were observed, photographed, numbered, and recorded segment by segment according to well number, depth, stratigraphic level, lithology, and reservoir space development characteristics. The focus was on identifying dissolution cavities, cavity filling materials, and their spatial relationship with the surrounding matrix, and selecting well-preserved, clearly defined, and representative core segments. During sample selection, core segments with bright crystalline carbonate minerals and quartz-filled / partially filled dissolution cavities within the dissolution cavities were prioritized.

[0025] like Figure 2 As shown, all core samples of the Longwangmiao Formation carbonate rocks from the three work areas exhibited typical dissolution pore structures. Based on the degree of filling, these pores can be classified into fully filled pores and partially filled pores. For pores of different filling types, their morphology and degree of filling were recorded.

[0026] After identifying the target cavity, location sampling is performed at the site of the dissolved cavity. The sampling area should include at least the cavity-filling mineral and its adjacent surrounding rock. If necessary, the cavity edge, cavity center, and residual pore locations should also be preserved to avoid obtaining only a single mineral without being able to determine its filling location and growth generation. The sample cutting direction should fully expose the main filling structure and mineral growth relationship of the cavity, thereby preserving the superposition of filling minerals from different stages or the characteristics of the cavity wall growing towards the center.

[0027] The obtained core samples were processed into double-sided polished fluid inclusion thin sections according to the requirements for fluid inclusion sample preparation. During the thin section processing, high temperature, strong acid, contaminant adhesion, or excessive grinding should be avoided to prevent affecting the integrity of the fluid inclusions. The thickness of the thin section should meet the requirements for polarized light microscopy, cathodoluminescence analysis, and in-situ laser Raman spectroscopy. The prepared fluid inclusion thin sections should have a smooth surface, be double-sided polished, and have clear mineral crystal and inclusion boundaries, so as to be used for subsequent classification of mineral generations filling dissolution cavities, identification of fluid inclusion assemblages, and calculation of abundance parameters of bituminous fluid inclusion assemblages.

[0028] S2. Microscopic petrological characteristics analysis of minerals filling dissolution cavities: Based on polarized light microscopy and cathodoluminescence (CL) technology, microscopic petrological characteristics analysis was conducted on the minerals filling dissolution cavities in the fluid inclusion thin sections. Polarized light microscopy was used to identify the mineral types, crystal morphology, crystal contact relationships, filling locations, and pore occupancy patterns of the filling minerals. Simultaneously, cathodoluminescence images were combined to analyze the luminescence characteristics and spatial distribution of different minerals or different growth zones to distinguish different cementing mineral generations.

[0029] The above analysis clarifies the mineral composition of the filling minerals within the dissolution cavities, including dolomite, calcite, quartz, and other possible associated minerals. Based on the replacement and superposition of minerals, pore wall growth, and residual pore occupancy, the relative growth sequence of the filling minerals is established. For the same mineral but with significant differences in cathodoluminescence characteristics, crystal morphology, or spatial location, it is classified into different mineral generations to avoid mixing fluid inclusions formed at different times in statistical analysis. Therefore, a fluid capture time series corresponding to different filling mineral generations is established, providing petrographic constraints for subsequent FIA identification, fluid system identification, and ABIA statistical analysis.

[0030] Figure 3 The image shows the microlithological characteristics of the karst cavities in the Longwangmiao Formation carbonate rocks in different work areas, along with corresponding cathodoluminescence images. The cavities are mostly completely or partially filled. Figure 3In the diagram, a, b, and c represent completely filled dissolution cavities; d, e, and f represent incompletely filled dissolution cavities. The early filling minerals are primarily euhedral to subhedral massive dolomite; later fillings are typically euhedral massive quartz filling the cavities or residual pore spaces. Furthermore, the euhedral to subhedral massive dolomite developed within the cavities exhibits significant differences from the microcrystalline dolomite within the cavities in terms of crystal morphology, pore location, and cathodoluminescence characteristics. Therefore, the occurrence of euhedral massive dolomite is clearly not from the same generation as the microcrystalline dolomite.

[0031] S3. Petrographic Analysis of Fluid Inclusion Assemblages and Identification of Fluid Methane Saturation: Using fluid inclusion assemblages (FIAs) as the basic analytical unit, microscopic petrographic observations are conducted on fluid inclusions within the same type or generation of infilling minerals. The observations include the morphology, size, location, gas-liquid ratio, phase composition, and co-occurrence relationships of the fluid inclusions to determine the phase type of each individual inclusion under room temperature conditions, including single-phase inclusions, two-phase inclusions (gas-liquid phases), and inclusions containing solid phases. For two-phase inclusions, the focus is on bubble morphology, gas volume, and gas-liquid ratio; for single-phase inclusions, the focus is on transparency, color, and co-occurrence relationships with adjacent inclusions. By comparing the gas-liquid ratio and phase characteristics of different inclusions within the same FIA, it can be determined whether the group of inclusions has relatively consistent trapping characteristics, providing petrographic evidence for subsequent fluid system identification.

[0032] Laser Raman spectroscopy was further employed to perform in-situ non-destructive testing on the gas phase components in the two-phase fluid inclusions and the internal components of the single-phase fluid inclusions. By identifying the characteristic Raman peaks of methane, single-phase methane inclusions and two-phase fluid inclusions containing methane were confirmed. The laser Raman test results were cross-validated with the micro-lithographic observation results to improve the reliability of fluid inclusion type identification and fluid system identification.

[0033] In fluid system identification, the phase combination and gas-liquid ratio consistency of inclusions within the same FIA ​​are the main criteria. If there are significant differences in the gas-liquid ratio of different inclusions within the same FIA, it indicates that the inclusions were formed through non-uniform capture. If a single-phase methane inclusion and a two-phase methane-containing gas-liquid inclusion coexist in the FIA, then the system corresponding to the FIA ​​at the time of capture is identified as a methane-supersaturated fluid system. This combination reflects the existence of an independent methane-enriched phase in the fluid system at the time of capture, thus easily forming a non-uniform capture characteristic with coexistence of single-phase methane inclusions and two-phase methane-containing gas-liquid inclusions, and significant variations in the gas-liquid ratio.

[0034] If only two-phase methane inclusions (gas-liquid two-phase inclusions) develop within the same FIA ​​(Fluid Inclusion Area), and the gas-liquid ratio of each inclusion is basically the same, without any single-phase methane inclusions coexisting with it, it indicates that this group of inclusions was formed by the capture of a homogeneous methane-containing fluid, and the capture was identified as an unsaturated methane fluid system. To ensure the accuracy of the identification, before performing the above identification, the morphology, boundary integrity, and spatial distribution characteristics of the inclusions should be considered to rule out abnormal gas-liquid ratios caused by factors such as later leakage and stretching.

[0035] Figure 4 The microlithological characteristics of fluid inclusion assemblages and the laser Raman spectroscopy results of some representative inclusions are shown. Figure 4 In Figure 1, a, b, c, and d represent completely filled dissolution pores; e, f, g, and h represent incompletely filled dissolution pores. As can be seen from the figure, there are significant differences in the fluid inclusion combinations and fluid system properties among the samples from different work areas: In work area A, the fluid inclusion combination is mainly composed of single-phase methane inclusions and gas-liquid two-phase methane-containing inclusions, with a significant difference in the gas-liquid ratio, exhibiting an overall methane supersaturated fluid system; In work areas B and C, the fluid inclusions are mainly gas-liquid two-phase methane-containing inclusions with a basically consistent gas-liquid ratio, with little or no single-phase methane inclusions, exhibiting an overall methane unsaturated fluid system.

[0036] S4. The thermal cracking origin of the ancient oil reservoir was confirmed. Laser Raman spectroscopy was used to perform in-situ non-destructive identification of the solid phase material within fluid inclusions in the aforementioned methane supersaturated and unsaturated fluid systems, with a focus on detecting whether solid bitumen developed within the inclusions. Raman testing was performed on inclusions containing visible solid particles, dark solid phases, or opaque materials under a microscope to determine whether the solid phase material was solid bitumen.

[0037] When methane-rich (or methane-containing) inclusions are observed coexisting with solid bitumen-containing inclusions confirmed by laser Raman spectroscopy in the same type or generation of infilling minerals, and both belong to the same fluid inclusion assemblage, it can be determined that the FIA ​​records the ancient reservoir's thermal cracking and the capture of hydrocarbon-rich gases and solids. This determination is not based solely on the presence of solid bitumen in the minerals, but rather on the criterion of "coexistence of methane-containing fluid inclusions and solid bitumen-containing inclusions in the same FIA ​​within the same mineral generation," thereby correlating bitumen-containing inclusions with specific phases of hydrocarbon evolution.

[0038] In this type of FIA, solid bitumen inclusions reflect hydrocarbon information formed and sealed by filling minerals during the thermal evolution, cracking, or fluid alteration of crude oil; the associated methane-rich (or methane-containing) inclusions reflect the participation or enrichment of methane in the fluid system during that period. Therefore, the aforementioned solid bitumen inclusion assemblages can serve as effective indicators for identifying fluid activities related to crude oil cracking in ancient reservoirs and should be included in the statistical scope of bitumen fluid inclusion assemblages abundance (ABIA).

[0039] In this embodiment, as Figure 4 As shown, samples from work areas A, B, and C all exhibited fluid inclusion assemblages coexisting with methane-rich (containing) inclusions and solid bitumen-containing inclusions. After confirmation by microscopic petrographic observation and laser Raman spectroscopy, these assemblages were identified as effective bitumen-containing fluid inclusion assemblages related to crude oil cracking in ancient reservoirs, and can serve as fundamental data for subsequent calculation of ABIA parameters in each work area and comparison of the original charge scale of the ancient reservoirs.

[0040] S5. Abundance ABIA calculation of bituminous fluid inclusion assemblages: For the same type or generation of filling minerals in the dissolution cavities, under unified microscopic observation magnification, statistical range, and fluid inclusion assembly identification criteria, the fluid inclusion assemblages developed within the minerals are identified and counted on a field-by-field basis. A fluid inclusion assembly (FIA) with a clear spatial coexistence relationship, facies characteristics, and petrographic classification is considered an independent statistical unit; even if multiple fluid inclusions are contained within the same FIA, they are still counted as only one fluid inclusion assembly, thus avoiding double counting due to differences in the number, size, or local density of individual inclusions.

[0041] Further in-situ laser Raman spectroscopy was used to detect the identified fluid inclusion assemblies. Fluid inclusion assemblies confirmed by laser Raman spectroscopy to contain solid bitumen components were recorded as effective bitumen-containing fluid inclusion assemblies, and their number was counted as N. bitumen Simultaneously, the number of all effectively identifiable fluid inclusion combinations in the same type or generation of infilling minerals is counted and denoted as N. total ;in, For N total A subset thereof, the total fluid inclusions include both asphalt-containing fluid inclusions and other types of fluid inclusions that do not contain asphalt.

[0042] Based on the above statistical results, the abundance of bitumen-bearing inclusion assemblages (ABIA) is calculated using the following formula:

[0043]

[0044] In the formula, ABIA represents the relative proportion of bituminous fluid inclusion assemblages within all fluid inclusion assemblages in a specific mineral generation and a specific diagenetic-fluid activity stage. Compared to directly using the absolute number of bituminous fluid inclusion assemblages, ABIA uses a normalized ratio, which can effectively reduce the impact of differences in mineral content, thin section area, number of observation fields, inclusion development density, and local heterogeneity between different samples on the statistical results. Simultaneously, limiting the statistical objects to the same type or generation of infilling minerals avoids the mixing of inclusion information from different diagenetic stages, different cementing minerals, and different fluid activity periods, ensuring that the obtained ABIA parameters correspond to a relatively clear fluid charging-modification stage. A higher ABIA value indicates a larger proportion of bituminous fluid inclusion assemblages in that mineral generation, meaning a more prevalent record of bituminous-related hydrocarbon charging, cracking, or modification fluid activities at that stage; a lower ABIA value indicates a relatively weaker microscopic record of this type of fluid activity.

[0045] S6. Identification of the original charging scale of ancient oil reservoirs and verification of production data: Compare the differences in the combined abundance ABIA of the same geological stratum at different structural locations or in different zones, and verify them in conjunction with the current natural gas production characteristics and production data of the corresponding work area, so as to identify and compare the original charging scale of ancient oil reservoirs in different zones.

[0046] A comparison was made of ABIA parameters obtained from different work areas of the Longwangmiao Formation in the Sichuan Basin. The results showed that ( Figure 5 The calculated ABIA value of work area A is significantly higher than that of work areas B and C. The abundance difference of this combination is compared with the daily natural gas production data of the corresponding work areas. The high ABIA value of the daily natural gas production of a single well in work area A indicates that the original charging scale of the ancient reservoir in work area A is the largest.

[0047] The scheme provided by this invention first screens carbonate reservoir samples with developed dissolution cavities at the core scale, and then performs targeted sampling, thin section preparation, and fluid inclusion thin section preparation at the locations of the dissolution cavities. Subsequently, using techniques such as polarized light microscopy petrographic observation and cathodoluminescence analysis, the mineral composition, crystal occurrence, cementation generations, growth relationships, and mineralogical and petrological characteristics of different filling minerals in the dissolution cavities are precisely determined. Furthermore, using fluid inclusion assemblages (FIA) as the basic analytical unit, the occurrence characteristics, petrographic features, and fluid system properties of various fluid inclusion assemblages are identified and determined.

[0048] Based on this, according to the spatial co-occurrence relationship of fluid inclusions in the same type or generation of infilling minerals, the total number of fluid inclusion assemblages developed was identified and counted in each field of view. Simultaneously, combined with in-situ laser Raman spectroscopy, the presence of solid bitumen in the inclusion assemblages was accurately identified, and bitumen-containing fluid inclusion assemblages were screened from different types of fluid inclusion assemblages. Furthermore, the ratio of the number of bitumen-containing fluid inclusion assemblages in the same type or generation of infilling minerals to the total number of analyzed fluid inclusion assemblages was calculated to obtain the bitumen-containing fluid inclusion assemblage abundance parameter (ABIA).

[0049] Finally, the ABIA parameters obtained from different regions or zones were jointly analyzed and verified with production data such as current natural gas production, single-well production capacity, stable production capacity, and production decline characteristics of the corresponding regions to establish the correlation between the abundance of bituminous fluid inclusion assemblages and the degree of natural gas enrichment. This allows for the identification, horizontal comparison, and evaluation of favorable zones in ancient carbonate reservoirs, providing a basis for the study of natural gas enrichment patterns and the selection of exploration targets.

[0050] This method only requires conventional mineralogy and petrology analysis, fluid inclusion assemblage (FIA) microlithogeographic observation, laser Raman spectroscopy analysis, and statistical analysis to identify and compare the original charging scale of ancient reservoirs in specific regions. Its core advantage and beneficial effect is that it can effectively eliminate heterogeneous interference caused by later stimulation.

[0051] This invention can help in the research on the identification of the scale of deep to ultra-deep carbonate paleooil reservoirs, and provide quantitative support for the evaluation of the resource potential of fractured gas reservoirs and the exploration deployment of high-quality zones.

[0052] The foregoing has described specific embodiments of this specification. Other embodiments are within the scope of the appended claims. In some cases, the actions, steps, or modules recited in the claims may be performed in a different order than that shown in the embodiments and may still achieve the desired results. Furthermore, the processes depicted in the drawings do not necessarily require the specific or sequential order shown to achieve the desired results. In some embodiments, multitasking and parallel processing are also possible or may be advantageous.

Claims

1. A method for identifying the size of paleooil reservoirs in carbonate rocks based on the abundance of bituminous inclusion assemblages, characterized in that, Includes the following steps: S1. Collect core samples from the target layer carbonate rock natural gas reservoir, select core segments with dissolution cavities, and take samples at the locations where the dissolution cavities are developed to prepare double-sided polished fluid inclusion thin sections. S2. Conduct petrological analysis on the filling minerals in the dissolution cavities of fluid inclusions to identify the mineral types, crystal morphology, and generational growth relationships of the filling minerals, and establish the time series of fluid capture. S3. Using fluid inclusion assemblages as the basic analytical unit, perform microscopic petrographic observation on the fluid inclusions trapped inside the filling minerals to determine the phase type and composition of each individual inclusion in the fluid inclusion assemblages at room temperature. Use laser Raman spectroscopy to perform in-situ non-destructive identification of the gas phase components in the gas-liquid two-phase inclusions and the components of the single-phase inclusions, identify single-phase methane inclusions and gas-liquid two-phase methane-containing inclusions, and determine whether the fluid inclusion assemblages were captured as a methane supersaturated fluid system or a methane unsaturated fluid system. S4. Use laser Raman spectroscopy to identify the solid phase material in the fluid inclusions of the above-mentioned methane supersaturated fluid system and methane unsaturated fluid system in situ to determine whether solid bitumen is contained inside the inclusions. S5. For the same type or generation of filling minerals in the dissolution cavities, count the number N of effective fluid inclusion combinations containing solid bitumen, confirmed by laser Raman spectroscopy. bitumen And the total number of fluid inclusion combinations N analyzed in the mineral. total Calculate the abundance of asphalt fluid inclusion assemblages (ABIA); S6. Compare the abundance differences of the combinations in different structural locations or zones within the same geological stratum, and verify them in conjunction with the current natural gas production characteristics and production data of the corresponding regions, thereby identifying and comparing the original charging scale of ancient oil reservoirs in different zones.

2. The method for identifying the size of paleooil reservoirs in carbonate rocks based on the abundance of bituminous inclusion assemblages according to claim 1, characterized in that, The specific approach of S2 is as follows: use a polarizing microscope to identify the mineral type, crystal morphology, crystal contact relationship, filling position and pore occupancy mode of the filling mineral; at the same time, combine cathodoluminescence images to analyze the luminescence characteristics and spatial distribution of different minerals or different growth zones in order to distinguish different cementing mineral generations.

3. The method for identifying the size of paleooil reservoirs in carbonate rocks based on the abundance of bituminous inclusion assemblages according to claim 1, characterized in that, In step S3, the fluid system identification method is as follows: if the gas-liquid two-phase methane inclusions in the same fluid inclusion combination have different gas-liquid ratios, and the fluid inclusion combination simultaneously contains single-phase methane inclusions and gas-liquid two-phase methane inclusions, then the fluid inclusion combination is identified as a methane supersaturated fluid system when it is captured; if the same fluid inclusion combination contains only gas-liquid two-phase methane inclusions, and the gas-liquid two-phase methane inclusions have the same gas-liquid ratio, then the fluid inclusion combination is identified as a methane unsaturated fluid system when it is captured.

4. The method for identifying the size of paleooil reservoirs in carbonate rocks based on the abundance of bituminous inclusion assemblages according to claim 1, characterized in that, In step S4, the specific method for determining whether solid bitumen is present inside the inclusion is as follows: if a combination of methane-rich inclusions and solid bitumen-containing fluid inclusions is observed in the filling minerals, it is determined that the fluid captured in this period is of ancient reservoir origin from crude oil thermal cracking, and the solid bitumen-containing inclusions are effective indicators for evaluating the scale of ancient reservoirs.

5. The method for identifying the size of paleooil reservoirs in carbonate rocks based on the abundance of bituminous inclusion assemblages according to claim 1, characterized in that, In step S5, the formula for calculating the abundance ABIA of the bituminous fluid inclusions is as follows: 。

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