Quantitative geological evaluation method for large-scale high-quality carbonate reservoir

Abstract

The invention relates to the technical field of lithofacies paleogeography and reservoir geology, in particular to a carbonate rock large-scale high-quality reservoir quantitative geological evaluation method, which comprises the following steps of: 1, determining compilation of a carbonate rock lithofacies base map; 2, identifying a carbonate rock paleogeographic pattern and a high-quality reservoir facies belt; 3, quantitatively depicting a high-quality reservoir sedimentary body, and expressing a geologic body structure; 4, judging the type of the storage space; and 5, analyzing the diagenesis and diagenesis sequence of the large-scale reservoir. According to the method, quantitative geological evaluation of the large-scale high-quality reservoir of the carbonate rock can be well carried out.

Description

Technical Field

[0001] The invention relates to the technical field of lithofacies paleogeography and reservoir geology, and in particular to a quantitative geological evaluation method for large-scale high-quality carbonate reservoirs. Background Art

[0002] The quantitative evaluation technology of high-quality carbonate reservoirs mainly involves a series of geological and geophysical methods to study the genesis, evolution and reservoir performance of carbonate reservoirs. Its technical background covers multidisciplinary knowledge, especially sedimentology, petrography, geophysics, rock physics and oil and gas exploration technology.

[0003] The current quantitative evaluation technology is mainly used to evaluate the storage space, pore structure, physical parameters and storage capacity of carbonate reservoirs for oil and gas. The following are common quantitative evaluation technologies and their defects:

[0004] 1. Sedimentary facies and lithofacies analysis

[0005] Data limitations: Sedimentary facies and lithofacies analysis often relies on core, thin section and outcrop data, which are localized and difficult to cover large areas. This limitation may lead to inaccurate predictions of the overall reservoir distribution and characteristics, especially in areas without sufficient data coverage.

[0006] Lateral discontinuity: Carbonate reservoirs have dramatic lateral variations, and sedimentary facies may change significantly over a short distance. Sedimentary facies analysis based on local cores and outcrops is difficult to reflect this complex lateral variation.

[0007] Subjectivity of lithofacies description: The description of sedimentary facies and lithofacies relies on the subjective judgment of geologists. Although there are certain standardized procedures, different researchers may have differences in analysis and interpretation, leading to inconsistent results.

[0008] 2. Paleogeographic reconstruction

[0009] Uncertainty in geological history: Paleogeographic reconstructions often rely on speculation about paleo-tectonic, paleoclimate, and paleo-ocean environments, which can be subject to significant uncertainty in geological history. In particular, when the sediment record is incomplete or the strata have been strongly altered, the accuracy of the reconstruction results will be affected.

[0010] High data dependence: Paleogeographic reconstruction requires a large amount of sedimentary, tectonic and climate data, but these data are not always available, especially in complex tectonic settings or areas with scarce geological records.

[0011] Influence of complex geological events: Geological events such as tectonic movements, sea level changes, and sediment supply have a profound impact on reservoir formation, and these events often occur in multiple phases and overlap with each other, making paleogeographic reconstruction more difficult.

[0012] 3. Well logging and seismic inversion technology

[0013] Resolution limitation: Although seismic inversion technology can provide a wide range of three-dimensional reservoir information, it is difficult to accurately capture the microscopic pore structure in carbonate reservoirs due to the resolution limitation of seismic waves, especially in the identification of complex structures such as dissolution pores and fractures.

[0014] Uncertainty in logging interpretation: The porosity and permeability of carbonate reservoirs are affected by the limitations of logging tools. Due to the diversity of pore structures in carbonate reservoirs (primary pores, secondary pores, fractures, etc.), it is difficult for a single logging method to fully reflect the true nature of the reservoir, and the accuracy of logging interpretation depends on experience.

[0015] Multiple solutions: When dealing with complex carbonate reservoirs, seismic inversion and well logging analysis often have multiple solutions, that is, multiple different geological models may explain the same well logging or seismic data. This increases the uncertainty of reservoir evaluation and requires other information to assist in judgment.

[0016] 4. Reservoir modeling and numerical simulation

[0017] Model dependency: The results of reservoir modeling are highly dependent on the quality of the input data and the assumptions. If the data is incomplete or there are deviations in the data processing, the model results may be inaccurate. In addition, some assumptions in the model (such as the homogeneity of the rock, the flow characteristics of the fluid, etc.) may not match the actual situation.

[0018] Difficulty in modeling complex reservoirs: Carbonate reservoirs are highly heterogeneous and complex, especially when there are multiple pore types (such as fractures, dissolution pores, etc.). Conventional modeling methods are difficult to accurately characterize the complex structure of the reservoir.

[0019] High computational cost: Detailed reservoir modeling and fluid dynamic simulations require a lot of computing resources, especially in high-resolution 3D modeling and long-term fluid simulations, which are computationally expensive and may be difficult to complete in a short time.

[0020] 5. Diagenesis and pore structure analysis

[0021] Complexity of diagenesis: The diagenesis process of carbonate reservoirs is very complex, involving the superposition of multiple processes such as compaction, dissolution, cementation, and recrystallization. The impact of these diagenetic processes on pore structure is dynamic and often difficult to accurately quantify using existing experimental and analytical methods.

[0022] Irreversibility of pore structure: Diagenesis may produce irreversible changes in the pore structure of the reservoir, resulting in the loss of the original reservoir properties. For example, cementation may significantly reduce the permeability and porosity of the reservoir, while dissolution can increase porosity, but its distribution is often difficult to predict.

[0023] Difficulty in identifying pore types: The pore types in carbonate reservoirs are diverse and their causes are complex, especially the identification and quantitative description of secondary pores. The impact of these secondary pores on reservoir permeability and storage capacity is often difficult to accurately evaluate through traditional core observation and experimental methods.

[0024] 6. High-resolution imaging technology

[0025] Limited coverage: High-resolution imaging techniques (such as CT scanning and electron microscopy) can provide extremely detailed information on pore structure and rock texture, but their application is usually limited to small-scale samples in the laboratory and is difficult to promote in large-scale reservoirs.

[0026] High cost: The equipment and operating costs of high-resolution imaging techniques are high, especially for complex carbonate reservoirs. Widespread use of these techniques for quantitative evaluation may require a large investment of financial and human resources.

[0027] Technology dependence: The accuracy and effect of imaging technology are limited by equipment performance and operating experience. Different equipment or operators may produce inconsistent imaging results, which will affect the quantitative analysis of reservoir pore structure.

[0028] 7. Machine learning and artificial intelligence technologies

[0029] Model training depends on data: The application of machine learning technology in the quantitative evaluation of carbonate reservoirs depends on a large amount of high-quality training data. If the training data is not rich enough or the data quality is poor, the prediction ability of the model will be affected.

[0030] Poor interpretability: Although machine learning can provide efficient reservoir evaluation, its black-box nature makes the model less interpretable. Especially under complex geological conditions, the results of machine learning models may be difficult to link with actual geological processes.

[0031] Overfitting risk: When dealing with complex carbonate reservoirs, machine learning models may have overfitting problems, that is, the model performs well on the training data, but cannot be generalized to new reservoir data, resulting in inaccurate prediction results.

[0032] Therefore, a new quantitative geological evaluation method for large-scale high-quality carbonate reservoirs is needed to solve the above problems. Summary of the invention

[0033] The present invention provides a quantitative geological evaluation method for large-scale high-quality carbonate reservoirs, which combines paleogeographic analysis, quantitative analysis of diagenesis and tracking of fluid migration paths, and proposes a "phase control-diagenesis-fluid" ternary quantitative evaluation technology, which can more accurately predict the development of high-quality reservoirs.

[0034] The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to the present invention comprises the following steps:

[0035] 1. Determine the compilation of carbonate rock facies base map;

[0036] 2. Paleogeographic pattern of carbonate rocks and identification of high-quality reservoir facies;

[0037] 3. Quantitative characterization of high-quality reservoir sedimentary bodies to express the geological structure;

[0038] 4. Determine the type of reservoir space;

[0039] 5. Analyze large-scale reservoir diagenesis and diagenetic sequence.

[0040] Preferably, in step one, a simplified geological map is selected as the base map, and the base map includes: carbonate rock strata exposure, profiles, drilling distribution, fault distribution, and pinch-out line elements; the structure-genetic lithology column is identified according to the actual materials, and the top and bottom contact relationship, whether the strata are complete, thickness, and sedimentary structural elements with specific phases are marked.

[0041] Preferably, in step 2, the paleogeographic pattern of carbonate rocks is identified by different sedimentary patterns:

[0042] 2.1) The base of the sedimentary basin is stable and there is no obvious subsidence of the basin: When the sedimentation rate is moderate, carbonate rock deposition advances toward the sea, forming a pattern in which the platform area is thin and the platform margin is thick; in this case, the thickness of platform deposition is less than the thickness of platform margin deposition;

[0043] 2.2) The sinking rate of the sedimentary basin is lower than the carbonate rock deposition rate: In this case, carbonate rock deposition will advance toward the sea, forming a gently inclined surface; the sediment thickness gradually decreases from the platform to the edge to the basin, showing that the platform thickness is greater than the platform edge thickness, greater than the basin thickness, and the platform edge thickness does not increase significantly;

[0044] 2.3) The rate of sedimentary basin subsidence is comparable to the rate of carbonate deposition: This results in the accumulation of carbonate deposits in an aggradational manner, forming steep slopes with a sudden decrease in thickness in some areas; in this model, the thickness of the platform is close to that of the platform margin and is significantly greater than the thickness of the slope and basin.

[0045] Preferably, in step 2, the identification of high-quality reservoir facies belts includes identification of microfacies related to platform edge reefs, identification of shoal-related microfacies, and identification of microfacies related to mud mounds or shallow water within the platform;

[0046] The identification of microfacies related to bioherms at the platform margin includes the identification of biocemented limestone microfacies, granular marl and boulder limestone microfacies containing complete organisms and well-preserved endogenous-epigenetic fauna, bioclastic granular marl microfacies experiencing strong biological burrowing, bioclastic argillaceous limestone and granular limestone microfacies containing shells and abraded bone particles, and shelled bioclastic granular limestone microfacies containing spar cement.

[0047] The identification of beach-related microfacies includes the identification of core-shaped gravel limestone, grain limestone microfacies, and oolitic microfacies;

[0048] The identification of microfacies related to mud mounds or shallow water within platforms includes the identification of non-laminated spherulitic limestone and mudstone, laminated spherulitic bonded limestone microfacies, and aggregated limestone microfacies.

[0049] Preferably, step three specifically includes the following steps:

[0050] 3.1) Statistic the lithology content and thickness of high-quality reservoirs, and make corresponding contour maps. Statistic the percentage content of the constituent rock units, grainstones and microbial rocks of high-quality reservoirs, and make corresponding contour maps;

[0051] 3.2) Clarify the division of high-quality reservoir lithology units, and represent the lithology within the mapping unit with lithology patterns according to the dominant lithofacies method;

[0052] 3.3) Rock assemblages are expressed in percentage content; structural-genetic units are divided using the three-part method.

[0053] As a preference, in 3.1), specifically:

[0054] 3.1.1) Data collection and collation:

[0055] Reservoir lithology data: Obtain data related to reservoir lithology from well logging data and core analysis, including the thickness and percentage of each lithology;

[0056] Lithology classification: including the classification of stratified dolomite, stromatolite dolomite, thrombolite dolomite, and foamy dolomite;

[0057] 3.1.2) High-quality reservoir lithology statistics:

[0058] Calculate the total thickness and proportion of each type of lithology in each geological unit, and calculate the percentage of the thickness of this type of lithology in the reservoir to the total thickness of the reservoir; perform layer-by-layer statistics on each type of lithology to obtain the percentage content data of each type of lithology;

[0059] 3.1.3) Thickness statistics:

[0060] Summarize the thickness of various lithological layers, including grainstone and different types of microbial rocks; compare data from different well locations horizontally to analyze the spatial distribution trend of thickness;

[0061] 3.1.4) Production of contour map:

[0062] Lithology percentage contour map: Use the lithology percentage data of each well location to mark the lithology percentage of each well on the map, and perform interpolation operations to generate a lithology percentage contour map; different lithology units need to draw their own percentage contour maps separately;

[0063] Thickness contour map: Similarly, based on the thickness data of each well point, interpolation is performed and a thickness contour map is drawn to show the spatial variation trend of reservoir thickness.

[0064] As a preference, in 3.2), specifically:

[0065] 3.2.1) Principles of lithological unit division:

[0066] Dominant lithofacies method: The combination of different lithologies is divided according to the proportion of lithology content; the main lithology is used as the main basis for division, and the secondary lithology is reasonably combined according to the sedimentary environment and hydrodynamic conditions;

[0067] Lithology type restrictions: Lithology units are simplified to no more than three lithology combinations, and complex lithologies must be merged and combined according to certain rules;

[0068] 3.2.2) Division steps:

[0069] a. Determine the main lithology:

[0070] From the statistical data, find out the main lithology that accounts for more than 50% in each mapping unit. The main lithology will dominate the lithology division of the entire unit.

[0071] b. Sub-lithology combination:

[0072] Identify secondary lithologies with a percentage between 25-50% and combine them with the primary lithology;

[0073] Sub-lithologies with a proportion between 10-25% are also recorded and incorporated into the corresponding units through combination;

[0074] c.Combination Standards:

[0075] When combining, ensure that the combined lithologies reflect similar sedimentary environments or hydrodynamic conditions; the appearance of secondary lithologies cannot conflict with the laws of dominant lithologies;

[0076] 3.2.3) Lithology map production:

[0077] Lithologic symbol representation: When compiling maps, each lithologic unit is represented by different patterns and symbols. Based on the results of the division, a comprehensive lithologic map is drawn to show the spatial distribution of different lithologic combinations.

[0078] As a preference, in 3.3), specifically:

[0079] 3.3.1) The principle of three-part division of structure-cause unit:

[0080] Lower unit: The lithology content accounts for more than 50% and is located in the lowest layer;

[0081] Middle unit: The lithology content is between 25-50%, located in the middle layer;

[0082] Upper unit: lithology content is less than 25%, located in the uppermost layer;

[0083] 3.3.2) Methods of expressing single lithology:

[0084] When there is only one lithology, the upper, middle, and lower parts of the entire structural-genetic unit are represented by the same pattern, indicating that the lithology runs throughout the unit;

[0085] 3.3.3) Two methods of expressing lithology:

[0086] If there are two lithologies, and one lithology accounts for more than 50%, then that lithology will be repeated throughout the unit;

[0087] Another way of arranging the lithologies is by their content:

[0088] If the secondary lithology accounts for 25-50%, it occurs in the middle unit;

[0089] If the secondary lithology accounts for less than 25%, it occurs in the upper unit;

[0090] 3.3.4) Three methods of expressing lithology:

[0091] When there are three lithologies, they occur in the lower, middle, and upper units, according to their contents;

[0092] 3.3.5) Identification and representation of structural and hydrodynamic conditions:

[0093] In the structure-genesis unit, the width of the pattern is used to represent the structure and its corresponding hydrodynamic conditions:

[0094] Low-energy environment: forming limestone carbonate or matrix support structures, represented by narrow patterns, reflecting low energy conditions;

[0095] Medium-energy environment: carbonate rocks that form medium-grained support structures are represented by patterns of medium width, reflecting a medium-energy environment;

[0096] High-energy environment: forms bright crystal structure or grain-supported structure, represented by wide patterns, representing deposition in a high-energy environment;

[0097] 3.3.6) Lithology and structural pattern design:

[0098] Simple lithology: For a single lithology or a simple lithology combination, a fixed pattern symbol is used to represent it;

[0099] Complex lithology: For complex lithology combinations, design combination patterns according to lithology content:

[0100] The main lithology pattern is prominent, and an obvious legend symbol is used;

[0101] For secondary lithology or lithology with medium content, a second pattern symbol is superimposed on the main lithology pattern to indicate the relative content of the lithology;

[0102] When there are three lithologies, a combined pattern is added to the main pattern to reflect the proportion of the three lithologies;

[0103] Special genetic lithology: For special genetic or structural lithology, special pattern symbols are used to represent it;

[0104] 3.3.7) Thickness representation method. Lithology layers of different thicknesses can be distinguished in the legend by special symbols:

[0105] Thin layer: indicated by =;

[0106] Middle layer: indicated by ≠;

[0107] Thick layer: indicated by #;

[0108] These symbols can be combined with pattern designs to indicate changes in thickness of different lithologies.

[0109] Preferably, in step 4, the reservoir space types include framework residual pores, intergranular pores, intragranular dissolved pores, dolomite intercrystalline pores, dissolved pores and fractures.

[0110] Preferably, in step 5, the large-scale reservoir diagenesis includes destructive diagenesis and constructive diagenesis;

[0111] Destructive diagenesis reduces the porosity and permeability of the reservoir, which has adverse effects on reservoir quality, including cementation, compaction pressure solution and silicification;

[0112] Constructive diagenesis is beneficial to improving the pore structure of the reservoir and increasing the porosity and permeability of the reservoir, including dissolution, fracturing, dolomitization and recrystallization;

[0113] The diagenetic sequence analysis can be divided into the following stages:

[0114] A. Early diagenesis stage

[0115] Micritization: carbonate particles gradually transform into micrite carbonate, forming framework pores between particles; these pores help form reservoir space;

[0116] Cementation: Early dolomite fibrous and lamellae cements were formed, which played a role in resisting compaction, but some pores were also filled;

[0117] B. Middle diagenetic stage

[0118] Compaction and pressure solution: As the burial depth increases, the compaction effect intensifies, the reservoir porosity begins to decrease, and the pressure solution effect causes the pores between particles to further shrink;

[0119] Dolomitization: Dolomitization occurs in this stage, intercrystalline pores are generated, and some pore structures are improved;

[0120] C. Late diagenetic stage

[0121] Dissolution: In the later stage of burial, the dissolution of fluids is enhanced, forming dissolution pores and improving the porosity of the reservoir;

[0122] Fracturing: Tectonic movement triggers the development of fractures, increasing the permeability of the reservoir;

[0123] Effect of hydrocarbon charging: After hydrocarbon charging occurs, the fluid fills the pores, further affecting the porosity and permeability of the reservoir.

[0124] The main technical effects of the present invention are:

[0125] 1. Improve reservoir prediction accuracy

[0126] Accurately identify high-quality reservoirs: Through comprehensive analysis of sedimentary phases, diagenesis and fluid migration paths, the "phase control-diagenesis-fluid" ternary quantitative evaluation technology can accurately identify high-quality reservoirs. This technology can better distinguish different types of pores in carbonate reservoirs and their causes, effectively improve the ability to identify high-quality reservoirs, and avoid misjudgment or misjudgment in traditional evaluation methods.

[0127] Reduce the error in predicting lateral changes in reservoirs: Carbonate reservoirs usually have strong lateral heterogeneity. This technology can better predict the lateral changes of reservoirs through quantitative sedimentary body characterization based on paleogeographic analysis. This greatly reduces the prediction error caused by lateral discontinuity, thereby improving the accuracy and reliability of the reservoir.

[0128] 2. Refined analysis of diagenetic process

[0129] Accurately predict the impact of diagenesis on reservoirs: This technology clarifies the diagenetic dolomitization path and pore evolution process through quantitative analysis of different diagenetic sequences and diagenetic stages. This helps to accurately predict the impact of diagenesis on reservoir porosity and permeability, especially for the complex evolution of diagenesis and pore structure in deep dolomite reservoirs, and can provide more reliable predictions.

[0130] Quantitative analysis of diagenetic sequence and pore type: Diagenesis is often the key factor controlling reservoir porosity and permeability. This technology can quantitatively analyze the diagenetic sequence and the causes of different pore types, providing a scientific basis for the quantitative prediction of reservoir properties.

[0131] 3. More accurate fluid migration path tracking

[0132] Improve the accuracy of oil and gas injection area prediction: Through the migration path of the tracer fluid, the technology can accurately track the migration trajectory of oil and gas in the reservoir and clarify the oil and gas injection area and non-injection area. This capability is of great significance for optimizing the deployment of oil and gas wells and reducing the risk of dry well drilling, which directly improves the development efficiency of oil and gas resources.

[0133] Enhanced dynamic reservoir assessment capabilities: Tracking fluid migration paths not only helps identify oil and gas enrichment areas, but also enables dynamic assessment of oil and gas migration in reservoirs. This technology can help geologists and engineers assess fluid flow in real time during reservoir development, adjust development strategies in a timely manner, and maximize recovery.

[0134] 4. Breakthrough in deep reservoir development

[0135] Adapting to the complexity of deep carbonate reservoirs: Traditional evaluation methods are difficult to apply to deep carbonate reservoirs (such as the Deng 4 dolomite) due to their complex diagenesis and diverse pore structures. Through quantitative analysis of diagenetic stages and the combination of diagenetic sequence and pore genesis, this technology can effectively meet the evaluation challenges of deep reservoirs, provide accurate reservoir predictions, and promote the development of deep oil and gas resources.

[0136] Solving the confusion of dolomitization: Dolomitization is a common diagenetic process in deep carbonate reservoirs. This technology clarifies the cause of dolomitization and its impact on pore structure, effectively solving the uncertainty problem of reservoir prediction caused by dolomitization in the past.

[0137] 5. Quantitative geological evaluation improves exploration and development efficiency

[0138] Optimizing exploration and development decisions: Quantitative geological evaluation technology helps oil and gas companies make more scientific decisions and reduce blindness and exploration risks during exploration and development by providing accurate reservoir data and fluid migration path predictions. This can not only improve the success rate of oil and gas wells, but also reduce drilling and development costs.

[0139] Reducing unnecessary drilling work: Through more accurate reservoir evaluation, technology can avoid unnecessary drilling activities caused by reservoir prediction errors, reduce ineffective investment in exploration and development work, and improve overall economic benefits.

[0140] 6. Support multi-scale comprehensive analysis

[0141] Macro-micro combined reservoir evaluation: A significant effect of this technology is the organic combination of macro sedimentary phase and micro pore structure, which improves the comprehensiveness and precision of reservoir evaluation through multi-scale analysis. This combination can not only explain the large-scale sedimentary phase control, but also reveal the impact of micro pore structure on fluid migration and reservoir quality.

[0142] Achieve 3D detailed description of reservoirs: Through paleogeographic analysis, quantitative analysis of diagenesis and fluid tracing, this technology can achieve 3D detailed characterization of reservoirs and provide a more comprehensive reservoir description. This effect greatly enhances the accuracy of reservoir models and helps optimize oil and gas production strategies.

[0143] 7. Promote the development of carbonate reservoir research

[0144] Enriched the theory of carbonate reservoir genesis and evolution: By deeply analyzing the genesis of different diagenetic sequences and pore types, this technology provides new theoretical and practical basis for the formation and evolution of carbonate reservoirs. In particular, the research results of the technology fill certain theoretical gaps in the diagenetic process and fluid migration mechanism of deep reservoirs.

[0145] Promoting the integration of multidisciplinary technologies: This technology integrates the research methods of multiple disciplines such as sedimentology, paleogeography, diagenesis, geophysical analysis and fluid dynamics, and provides an important example for the multidisciplinary integration of reservoir evaluation technology. This will promote the development of the reservoir evaluation field in the future, especially in the comprehensive analysis of complex reservoirs. BRIEF DESCRIPTION OF THE DRAWINGS

[0146] Figure 1 This is a flow chart of a quantitative geological evaluation method for large-scale high-quality carbonate reservoirs; DETAILED DESCRIPTION

[0147] In order to further understand the content of the present invention, the present invention is described in detail in conjunction with the accompanying drawings and embodiments. It should be understood that the embodiments are only for explaining the present invention and are not intended to limit it.

[0148] Example

[0149] like Figure 1 As shown, this embodiment provides a quantitative geological evaluation method for large-scale high-quality carbonate reservoirs, which includes the following steps:

[0150] 1. Determine the compilation of carbonate rock facies base map;

[0151] A simplified geological map is selected as the base map, which mainly includes: carbonate rock strata exposure, profiles, well distribution, fault distribution, pinch-out line elements, and other basic map elements such as figure names, legends, etc.; the structure-genetic lithology column is identified according to the actual materials, and the top and bottom contact relationship, whether the strata are complete, thickness, and sedimentary structural elements with specific phases are marked.

[0152] 2. Paleogeographic pattern of carbonate rocks and identification of high-quality reservoir facies;

[0153] Identification of carbonate paleogeographic pattern

[0154] Differentiate by deposition mode:

[0155] 2.1) The base of the sedimentary basin is stable and there is no obvious subsidence of the basin: When the sedimentation rate is moderate, carbonate rock deposition advances toward the sea, forming a pattern in which the platform area is thin and the platform margin is thick; in this case, the thickness of platform deposition is less than the thickness of platform margin deposition;

[0156] 2.2) The sinking rate of the sedimentary basin is lower than the carbonate rock deposition rate: In this case, carbonate rock deposition will advance toward the sea, forming a gently inclined surface; the sediment thickness gradually decreases from the platform to the edge to the basin, showing that the platform thickness is greater than the platform edge thickness, and greater than the basin thickness (platform deposition thickness> platform edge deposition thickness> basin deposition thickness), and the platform edge thickness does not increase significantly;

[0157] 2.3) The sinking rate of the sedimentary basin is comparable to the sedimentation rate of carbonate rocks: This causes carbonate deposits to accumulate in an aggradational manner, forming steep slopes, and the thickness suddenly decreases in some areas; in this model, the platform thickness is close to the platform margin thickness, and is significantly greater than the slope and basin thickness (platform deposition thickness ≈ deposition thickness > slope deposition thickness, basin deposition thickness).

[0158] It is important to note that there is no direct correspondence between carbonate thickness and water depth. Greater carbonate thickness generally indicates that the subsidence rate and sedimentation rate of the sedimentary basin have been balanced for a long time, which does not necessarily mean that the water is deeper. Conversely, thinner carbonate layers may be associated with paleo-uplifts, or they may have been deposited in undercompensated or sediment-poor basins with deeper water bodies. Therefore, the interpretation of carbonate thickness requires a comprehensive analysis combined with other evidence from petrology and depositional environments.

[0159] Identification of high-quality reservoir facies

[0160] The formation of high-quality carbonate reservoirs is mainly controlled by two factors: the original sedimentary environment and the later diagenetic transformation (including diagenesis, tectonic action and fluid action). The sedimentary environment controls the distribution of favorable original sedimentary facies. The platform edge bioherms, microbial mounds and intra-platform microbial mounds are composed of microbial dolomite and granular dolomite with strong sedimentary hydrodynamics, with relatively high initial porosity and high permeability, and are the main large-scale high-quality reservoir rocks.

[0161] Identification of high-quality reservoir facies belts includes identification of microfacies related to platform margin reefs, beach-related microfacies, and microfacies related to mud mounds or shallow water within platforms;

[0162] The identification of microfacies related to bioherms at the platform margin includes the identification of biocemented limestone microfacies, granular marl and boulder limestone microfacies containing complete organisms and well-preserved endogenous-epigenetic fauna, bioclastic granular marl microfacies experiencing strong biological burrowing, bioclastic argillaceous limestone and granular limestone microfacies containing shells and abraded bone particles, and shelled bioclastic granular limestone microfacies containing spar cement.

[0163] Biocemented limestone microfacies: characterized by the in situ growth of potential reef-building organisms. It can be further subdivided according to growth morphology and inferred growth style, such as framework limestone, barrier limestone, cemented limestone, etc.

[0164] Microfacies of granular marl and boulder limestone containing complete organisms and well-preserved endogenous and epigenetic faunas, and microfacies of bioclastic granular marl that has undergone intense biological burrowing: the micritic sediments include dispersed small skeletal fragments, which provide the formation of fine-grained bone fragment matrix; the content of fossil fragments in the micritic sediments is common to abundant, and the bioclasts are often micritic. These sediments are mainly formed in low-energy environments below the wave base in fair weather or surrounded by reefs.

[0165] Microfacies of bioclastic mudstone and grain limestone containing encrustations and abraded skeletal particles: The bioclastics that have been abraded and encrusted are deposited in a fine-grained matrix to form mudstone and grain marl, showing the formation mechanism of high energy forming low-energy deposition, that is, matrix mud crystals + particles, formed in shelf lagoons and open shelves.

[0166] Microfacies of shelled bioclastic grain limestone containing sparry cement: most of the grains are bioclastics that are shelled by microorganisms, with micrite casing or complete micrite, indicating that the sedimentary environment is at or above the wave base under the action of waves on fair days; the spherule-like mud is filled between the grains, suggesting a back-reef beach in a high-energy environment outside the Taiwan Strait, that is, a sparry cement + grain model, formed above the wave impact surface, a high-energy sedimentary environment in the sand or reef.

[0167] The identification of beach-related microfacies includes the identification of core-shaped gravel limestone, grain limestone microfacies, and oolitic microfacies;

[0168] Oncolithic conglomerate limestone and grainstone microfacies: Millimeter- to centimeter-sized oncoliths (mainly crinoids and porous layered oncoliths) form grain-supported structures. Oncolithic conglomerate limestone and grainstone are commonly found in open sea-shaded marginal sandy beach areas, open shelf lagoons, platform patch reef environments, and the back-reef areas of large reef complexes.

[0169] Oolitic microfacies: Oolitic-rich carbonate sand aggregates occur at and near the seaward margins of platforms, beaches, and shelves, and can also form within platforms and on inner and intermediate gentle slopes. Oolitic-rich limestones are composed of large amounts of well-sorted and often densely packed oolitic grains, and often occur in cross-bedded stratigraphic units formed in high-energy environments such as oolite beaches, tidal bars, and beaches.

[0170] The identification of microfacies related to mud mounds or shallow water within platforms includes the identification of non-laminated spherulitic limestone and mudstone, laminated spherulitic bonded limestone microfacies, and aggregated limestone microfacies.

[0171] Microfacies of non-laminated spherulitic limestone and mudstone and laminated spherulitic cemented limestone: This type of microfacies is mainly divided into two subcategories based on the presence or absence of lamination:

[0172] When there are no laminae, fine-grained quasi-spherulitic limestones mainly form shallow subtidal zones with algal mound uplifts and have spar cements; when the roundness is poor and the quasi-spherulites are angular micrite fragments, they represent a relatively low-energy sedimentary confined intra-platform lagoon;

[0173] When it has a laminated structure, it is mainly composed of fine-grained spherulite limestone and mud crystal laminae. Laminated bonded limestone is commonly found in mud mounds, slopes and restricted platform environments. Laminated spherulite limestone is conducive to the formation of mud mounds and the stabilization of platform slopes.

[0174] Grainstone microfacies containing aggregated grains (granosite): Grainstone and grainstone-conglomerate limestone are mainly composed of sand fragments, gravel aggregates and grapestone, and are associated with spherulites and some encrustations and micritic skeletons. It is a typical product of the platform environment. The grapestone phase was formed within a few thousand meters behind the platform edge.

[0175] 3. Quantitative characterization of high-quality reservoir sedimentary bodies to express the geological structure;

[0176] The sedimentary environment controls high-quality reservoirs. The microbial mound-shoal phase with better initial physical properties is formed in a sedimentary environment with strong hydrodynamics. Its clot structure and the bedding structure of stromatolites give the rock a certain resistance to compaction, which is the material basis for reservoir development and is also conducive to later diagenetic transformation.

[0177] Through detailed dissection of field outcrops and identification of indoor rock thin sections, the carbonate reservoir rock types mainly include microbial dolomite, granular dolomite, and crystalline dolomite. Microbial dolomite develops microbial structures and is further divided into lamellar dolomite, stromatolite dolomite, thrombolite dolomite, foamy dolomite, etc. according to morphological characteristics. Crystalline dolomite can be divided into mudstone dolomite, powder crystal dolomite, and fine crystal dolomite according to grain size.

[0178] The specific steps include:

[0179] 3.1) Statistic the lithology content and thickness of high-quality reservoirs, and make corresponding contour maps. Statistic the percentage content of the constituent rock units of high-quality reservoirs, grainstone and microbial rock (stratified dolomite, stromatolite dolomite, thrombolite dolomite, foamy dolomite, etc.), and make corresponding contour maps.

[0180] Specifically:

[0181] 3.1.1) Data collection and collation:

[0182] Reservoir lithology data: Obtain data related to reservoir lithology from well logging data and core analysis, including the thickness and percentage of each lithology;

[0183] Lithology classification: including the classification of layered dolomite, stromatolite dolomite, thrombolite dolomite and foamy dolomite.

[0184] 3.1.2) High-quality reservoir lithology statistics:

[0185] Calculate the total thickness and proportion of each type of lithology in each geological unit, and calculate the percentage of the thickness of this type of lithology in the reservoir to the total thickness of the reservoir; conduct layer-by-layer statistics on each type of lithology (granular rock and different types of microbial rock) to obtain the percentage data of each type of lithology.

[0186] 3.1.3) Thickness statistics:

[0187] The thickness of various lithological layers was summarized, including grainstone and different types of microbial rocks; data from different well locations were compared horizontally to analyze the spatial distribution trend of thickness.

[0188] 3.1.4) Production of contour map:

[0189] Lithology percentage contour map: Use the lithology percentage data of each well location (for example, the percentage of stromatolite dolomite, etc.), mark the lithology percentage of each well on the map, and perform interpolation operations to generate a lithology percentage contour map; different lithology units need to draw their own percentage contour maps separately;

[0190] Thickness contour map: Similarly, based on the thickness data of each well point, interpolation is performed and a thickness contour map is drawn to show the spatial variation trend of reservoir thickness.

[0191] 3.2) Clarify the division of high-quality reservoir lithologic units and, based on the dominant lithofacies method, represent the lithologies within the mapping units with lithologic patterns.

[0192] Specifically:

[0193] 3.2.1) Principles of lithological unit division:

[0194] Dominant lithofacies method: The combination of different lithologies is divided according to the proportion of lithology content; the main lithology (accounting for more than 50%) is used as the main basis for division, and the secondary lithology (accounting for 25-50% and 10-25%) is reasonably combined according to the sedimentary environment and hydrodynamic conditions;

[0195] Restrictions on lithology types: The lithology units are simplified to no more than three lithology combinations, and complex lithologies must be merged and combined according to certain rules.

[0196] 3.2.2) Division steps:

[0197] a. Determine the main lithology:

[0198] From the statistical data, find out the main lithology (such as stratigraphic dolomite, grainstone, etc.) that accounts for more than 50% in each mapping unit. The main lithology will dominate the lithology classification of the entire unit.

[0199] b. Sub-lithology combination:

[0200] Identify secondary lithologies with a percentage between 25-50% and combine them with the primary lithology;

[0201] Sub-lithologies with a proportion between 10-25% are also recorded and incorporated into the corresponding units through combination;

[0202] c.Combination Standards:

[0203] When combining, ensure that the combined lithologies reflect similar sedimentary environments or hydrodynamic conditions; the appearance of secondary lithologies cannot conflict with the laws of dominant lithologies; for example, if the main lithology is grainstone, the secondary lithology cannot violate the hydrodynamic conditions and sedimentary environment laws of grainstone formation.

[0204] 3.2.3) Lithology map production:

[0205] Lithologic symbol representation: When compiling maps, each lithologic unit is represented by different patterns and symbols. Based on the results of the division, a comprehensive lithologic map is drawn to show the spatial distribution of different lithologic combinations.

[0206] 3.3) Rock assemblages are expressed in percentage content; structural-genetic units are divided using the three-part method.

[0207] Specifically:

[0208] 3.3.1) The principle of three-part division of structure-cause unit:

[0209] Lower unit: The lithology content accounts for more than 50% and is located in the lowest layer;

[0210] Middle unit: The lithology content is between 25-50%, located in the middle layer;

[0211] Upper unit: The lithology content is less than 25% and is located in the uppermost layer.

[0212] 3.3.2) Methods of expressing single lithology:

[0213] When there is only one lithology, the upper, middle, and lower parts of the entire structural-genetic unit are represented by the same pattern, indicating that the lithology runs through the entire unit; for example, if the entire unit is granular carbonate rock, the pattern of the three parts will remain consistent.

[0214] 3.3.3) Two methods of expressing lithology:

[0215] If there are two lithologies, and one lithology accounts for more than 50%, then that lithology will be repeated throughout the unit;

[0216] Another way of arranging the lithologies is by their content:

[0217] If the secondary lithology accounts for 25-50%, it occurs in the middle unit;

[0218] If the secondary lithology accounts for less than 25%, it occurs in the upper unit.

[0219] 3.3.4) Three methods of expressing lithology:

[0220] When there are three lithologies, they occur in the lower, middle, and upper units, according to their content; for example:

[0221] The main lithology (e.g., stratified dolomite, with a content of >50%) occurs in the lower part;

[0222] Secondary lithologies (e.g., thrombolite dolomite, 25-50%) occur in the middle;

[0223] The tertiary lithology (such as foamy dolomite, content <25%) appears in the upper part.

[0224] 3.3.5) Identification and representation of structural and hydrodynamic conditions:

[0225] In the structure-genesis unit, the width of the pattern is used to represent the structure and its corresponding hydrodynamic conditions:

[0226] Low-energy environment: forming limestone carbonate rock or matrix support structure, represented by narrow patterns (such as 2mm wide), reflecting low energy conditions;

[0227] Medium energy environment: carbonate rocks that form medium-sized grain support structures are represented by medium-width patterns (e.g., 3 mm wide), reflecting a medium-energy environment;

[0228] High-energy environment: A bright crystal structure or a particle support structure is formed, represented by a wide pattern (such as 4 mm wide), which represents deposition in a high-energy environment.

[0229] 3.3.6) Lithology and structural pattern design:

[0230] Simple lithology: For a single lithology or a simple lithology combination, a fixed pattern symbol is used to represent it;

[0231] Complex lithology: For complex lithology combinations, design combination patterns according to lithology content:

[0232] The main lithology pattern is prominent, and an obvious legend symbol is used;

[0233] For secondary lithology or lithology with medium content, a second pattern symbol is superimposed on the main lithology pattern to indicate the relative content of the lithology;

[0234] When there are three lithologies, a combined pattern is added to the main pattern to reflect the proportion of the three lithologies;

[0235] Special genetic lithology: Special genetic or tectonic lithology, such as biogenic dolomite or lithology related to tectonic activities, is represented by special pattern symbols.

[0236] 3.3.7) Thickness representation method. Lithology layers of different thicknesses can be distinguished in the legend by special symbols:

[0237] Thin layer: indicated by =;

[0238] Middle layer: indicated by ≠;

[0239] Thick layer: indicated by #;

[0240] These symbols can be combined with pattern designs to indicate changes in thickness of different lithologies.

[0241] 4. Determine the type of reservoir space;

[0242] The reservoir space types include framework residual pores, intergranular pores / intergranular dissolved pores, intragranular dissolved pores, dolomite intercrystalline pores / intercrystalline dissolved pores, dissolved pores (caves) and fractures. The main reservoir space type is dissolved pores (caves).

[0243] 4.1) Pore type

[0244] (1) Residual holes and holes in the grid

[0245] Description: Mainly developed in microbial dolomites such as stromatolites, thrombolites, and foam layers. After organic soluble substances such as cyanobacteria are dissolved during the sedimentation process, a large number of framework pores are formed, which are the primary pores in the dolomite reservoir.

[0246] Cause: Mainly from the dissolution of early organic matter, which retains the pores of the microbial structure.

[0247] (2) Intergranular pores and intergranular solution pores

[0248] Intergranular pores: Pores existing between carbonate rock particles, including primary and secondary pores, are pore spaces naturally formed during the sedimentation process.

[0249] Intergranular pores: secondary pores formed when diagenetic fluid dissolves the cement between particles.

[0250] (3) Intragranular pores

[0251] Description: It is formed inside the particles by dissolution during the diagenesis stage. When the particles are almost completely dissolved, the casting pores are formed.

[0252] Cause: Common in granular carbonate rocks, short-term freshwater dissolution in the penecontemporaneous period dissolved the soluble minerals (such as gypsum, halite, and aragonite) inside the particles.

[0253] (4) Intercrystalline pores and intercrystalline solution pores

[0254] Intercrystalline pores: pores between mineral crystals, commonly found in powder to fine-crystalline dolomite or medium-coarse-crystalline dolomite cements. The formation may be related to the reduction of solid volume during the dolomitization process.

[0255] Intercrystalline solution pores: secondary pores formed by the dissolution of dolomite grains on the basis of intercrystalline pores. The pore sizes of intercrystalline pores and intercrystalline solution pores are usually small, ranging from 0.01mm to 0.2mm.

[0256] 4.2) Dissolution holes

[0257] Description: Dissolution holes are the main storage space in the Dengying Formation reservoir, and the sizes of holes vary. Generally speaking, holes with a diameter greater than 2 mm are called dissolution holes.

[0258] Cause: It is formed by non-selective dissolution, which creates larger pore spaces in carbonate rocks and increases storage capacity.

[0259] 4.3) Cracks

[0260] Description: Fractures in carbonate rocks can be either tectonic or non-tectonic.

[0261] Structural fractures: caused by stress generated by regional tectonic movements, the structural fractures in the study area are well developed, with varying scales and multi-stage characteristics. The fractures can greatly enhance the permeability of the reservoir.

[0262] Non-tectonic fractures: caused by non-tectonic factors such as rock shrinkage and dissolution, which may have local effects.

[0263] 5. Analyze the large-scale reservoir diagenesis and diagenetic sequence;

[0264] Large-scale reservoir diagenesis includes destructive diagenesis and constructive diagenesis.

[0265] Destructive diagenesis reduces the porosity and permeability of the reservoir, and has adverse effects on reservoir quality, including cementation, compaction and pressure solution, and silicification.

[0266] Cementation:

[0267] Multi-stage mineral cementation is common in carbonate reservoirs, forming fibrous and foliated dolomite cements, quartz and other mineral cements. These minerals fill the pore space and significantly reduce the porosity of the reservoir.

[0268] Although early fibrous and foliated dolomite cements helped resist compaction and preserved some porosity, most cementation reduced the reservoir properties.

[0269] Compaction and pressure dissolution:

[0270] During the burial process, carbonate rocks are subjected to overlying pressure from rocks, which increases the contact surface between particles and reduces the pore space. Pressure solution further dissolves the cement between particles, exacerbating the reduction of reservoir pores.

[0271] The consequence of compaction is rock densification, which significantly reduces porosity and permeability, seriously affecting the quality of the reservoir.

[0272] Silicification:

[0273] Silicification refers to the replacement of carbonate minerals in carbonate rocks by siliceous minerals such as quartz. This process usually fills the original pores, making the reservoir dense, significantly reducing porosity and leading to a decrease in storage capacity.

[0274] Constructive diagenesis is beneficial to improving the pore structure of the reservoir and increasing the porosity and permeability of the reservoir, including dissolution, fracturing, dolomitization and recrystallization.

[0275] Dissolution: Dissolution is one of the most important constructive diagenesis in carbonate reservoirs. Dissolution forms new pores and solution pores through the dissolution of minerals by fluids, significantly increasing the porosity and permeability of the reservoir.

[0276] Dissolution can remove early cementation and expand intergranular and intercrystalline pores, especially in the late burial diagenesis stage. The formation of large pores (such as caves) can significantly improve reservoir performance.

[0277] Fracturing: Fracturing caused by tectonic movement and regional stress can form cracks in the reservoir. The development of cracks can greatly increase the permeability of the reservoir, especially in densely cemented carbonate reservoirs, where cracks provide effective channels for fluid migration.

[0278] Dolomitization: Dolomitization refers to the conversion of carbonate minerals into dolomite. During the dolomitization process, the volume usually decreases, and intercrystalline pores are generated, which is conducive to the improvement of reservoir porosity. Dolomite has a strong resistance to compaction and can resist the damage of later compaction and maintain the pore structure of the reservoir. In addition, dolomitization can also create conditions for dissolution and further improve the physical properties of the reservoir.

[0279] Recrystallization: Recrystallization refers to the reprecipitation of carbonate minerals to form larger crystals, which usually occurs under deeper burial conditions. Although this process may reduce the porosity of the reservoir, under certain conditions, recrystallization can optimize the pore structure and make the reservoir have better storage capacity.

[0280] Recrystallization can also repair some tiny pores formed by pressure solution and restore the permeability of the reservoir.

[0281] The diagenetic sequence analysis can be divided into the following stages:

[0282] A. Early diagenesis stage

[0283] Micritization: carbonate particles gradually transform into micrite carbonate, forming framework pores between particles; these pores help form reservoir space;

[0284] Cementation (early stage): Early dolomite fibrous and lamellae cements are formed, which play a role in resisting compaction, but some pores are also filled.

[0285] B. Middle diagenetic stage

[0286] Compaction and pressure solution: As the burial depth increases, the compaction effect intensifies, the reservoir porosity begins to decrease, and the pressure solution effect causes the pores between particles to further shrink;

[0287] Dolomitization: Dolomitization occurs in this stage, resulting in intercrystalline pores and partial improvement of the pore structure.

[0288] C. Late diagenetic stage

[0289] Dissolution: In the later stage of burial, the dissolution of fluids is enhanced, forming dissolution pores and improving the porosity of the reservoir;

[0290] Fracturing: Tectonic movement triggers the development of fractures, increasing the permeability of the reservoir;

[0291] Effect of hydrocarbon charging: After hydrocarbon charging occurs, the fluid fills the pores, further affecting the porosity and permeability of the reservoir.

[0292] This embodiment significantly improves the accuracy and reliability of reservoir prediction through the "phase control-diagenesis-fluid" ternary evaluation model, especially in the development of deep reservoirs and dolomite reservoirs. Its technical effect is not only outstanding in improving the efficiency of oil and gas exploration and development, but also has important significance in promoting the development of reservoir geology theory. This quantitative evaluation method can greatly reduce development risks, optimize the oil and gas production process, and bring significant economic benefits.

[0293] The present invention and its embodiments are described schematically above, and the description is not restrictive. The drawings show only one embodiment of the present invention, and the actual structure is not limited thereto. Therefore, if a person skilled in the art is inspired by it and designs a structural method and an embodiment similar to the technical solution without creativity without departing from the purpose of the invention, they shall all fall within the protection scope of the present invention.

Claims

1. A quantitative geological evaluation method for large-scale high-quality carbonate reservoirs, characterized by: The following steps are involved:

1. Determine the compilation of carbonate rock facies base map; 2. Paleogeographic pattern of carbonate rocks and identification of high-quality reservoir facies; 3. Quantitative characterization of high-quality reservoir sedimentary bodies to express the geological structure; 4. Determine the type of reservoir space; 5. Analyze large-scale reservoir diagenesis and diagenetic sequence.

2. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 1, characterized in that: In step one, a simplified geological map is selected as the base map, which includes: carbonate strata exposure, profiles, well distribution, fault distribution, and pinch-out line elements; the structure-genetic lithology column is identified based on actual materials, and the top and bottom contact relationship, whether the strata are complete, thickness, and sedimentary structural elements with specific phases are marked.

3. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 2, characterized in that: In step 2, the paleogeographic pattern of carbonate rocks is identified by different sedimentary patterns: 2.1) The base of the sedimentary basin is stable and there is no obvious subsidence in the basin: when the sedimentation rate is moderate, carbonate rock deposition advances toward the sea, forming a pattern in which the platform area is thin and the platform margin is thick; the thickness of platform deposition is less than the thickness of platform margin deposition; 2.2) The sinking speed of the sedimentary basin is lower than the carbonate rock deposition speed: carbonate rock deposition will advance toward the sea, forming a gently inclined surface; the sediment thickness gradually decreases from the platform to the edge to the basin, showing that the platform thickness is greater than the platform edge thickness, greater than the basin thickness, and the platform edge thickness does not increase significantly; 2.3) The sinking rate of the sedimentary basin is comparable to the deposition rate of carbonate rocks: this results in the accumulation of carbonate deposits in an aggradational manner, forming steep slopes, with the thickness suddenly decreasing in some areas; the thickness of the platform is close to that of the platform margin, and is significantly greater than the thickness of the slope and basin.

4. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 3, characterized in that: In step 2, the identification of high-quality reservoir facies belts includes identification of microfacies related to platform margin reefs, identification of microfacies related to shoals, and identification of microfacies related to mud mounds or shallow water within platforms; The identification of microfacies related to bioherms at the platform margin includes the identification of biocemented limestone microfacies, granular marl and boulder limestone microfacies containing complete organisms and well-preserved endogenous-epigenetic fauna, bioclastic granular marl microfacies experiencing strong biological burrowing, bioclastic argillaceous limestone and granular limestone microfacies containing shells and abraded bone particles, and shelled bioclastic granular limestone microfacies containing spar cement. The identification of beach-related microfacies includes the identification of core-shaped gravel limestone, grain limestone microfacies, and oolitic microfacies; The identification of microfacies related to mud mounds or shallow water within platforms includes the identification of non-laminated spherulitic limestone and mudstone, laminated spherulitic bonded limestone microfacies, and aggregated limestone microfacies.

5. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 4, characterized in that: Step three specifically includes the following steps: 3.1) Statistic the lithology content and thickness of high-quality reservoirs, and make corresponding contour maps. Statistic the percentage content of the constituent rock units, grainstones and microbial rocks of high-quality reservoirs, and make corresponding contour maps; 3.2) Clarify the division of high-quality reservoir lithology units, and represent the lithology within the mapping unit with lithology patterns according to the dominant lithofacies method; 3.3) Rock assemblages are expressed in percentage content; structural-genetic units are divided using the three-part method.

6. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 5, characterized in that: 3.1), specifically: 3.1.1) Data collection and collation: Reservoir lithology data: Obtain data related to reservoir lithology from well logging data and core analysis, including the thickness and percentage of each lithology; Lithology classification: including the classification of stratified dolomite, stromatolite dolomite, thrombolite dolomite, and foamy dolomite; 3.1.2) High-quality reservoir lithology statistics: Calculate the total thickness and proportion of each type of lithology in each geological unit, and calculate the percentage of the thickness of this type of lithology in the reservoir to the total thickness of the reservoir; perform layer-by-layer statistics on each type of lithology to obtain the percentage content data of each type of lithology; 3.1.3) Thickness statistics: Summarize the thickness of various lithological layers, including grainstone and different types of microbial rocks; compare data from different well locations horizontally to analyze the spatial distribution trend of thickness; 3.1.4) Production of contour map: Lithology percentage contour map: Use the lithology percentage data of each well location to mark the lithology percentage of each well on the map, and perform interpolation operations to generate a lithology percentage contour map; different lithology units need to draw their own percentage contour maps separately; Thickness contour map: Similarly, based on the thickness data of each well point, interpolation is performed and a thickness contour map is drawn to show the spatial variation trend of reservoir thickness.

7. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 6, characterized in that: 3.2), specifically: 3.2.1) Principles of lithological unit division: Dominant lithofacies method: The combination of different lithologies is divided according to the proportion of lithology content; the main lithology is used as the main basis for division, and the secondary lithology is reasonably combined according to the sedimentary environment and hydrodynamic conditions; Lithology type restrictions: Lithology units are simplified to no more than three lithology combinations, and complex lithologies must be merged and combined according to certain rules; 3.2.2) Division steps: a. Determine the main lithology: From the statistical data, find out the main lithology that accounts for more than 50% in each mapping unit. The main lithology will dominate the lithology division of the entire unit. b. Sub-lithology combination: Identify secondary lithologies with a percentage between 25-50% and combine them with the primary lithology; Sub-lithologies with a proportion between 10-25% are also recorded and incorporated into the corresponding units through combination; c.Combination Standards: When combining, ensure that the combined lithologies reflect similar sedimentary environments or hydrodynamic conditions; the appearance of secondary lithologies cannot conflict with the laws of dominant lithologies; 3.2.3) Lithology map production: Lithologic symbol representation: When compiling maps, each lithologic unit is represented by different patterns and symbols. Based on the results of the division, a comprehensive lithologic map is drawn to show the spatial distribution of different lithologic combinations.

8. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 7, characterized in that: 3.3), specifically: 3.3.1) The principle of three-part division of structure-cause unit: Lower unit: The lithology content accounts for more than 50% and is located in the lowest layer; Middle unit: The lithology content is between 25-50%, located in the middle layer; Upper unit: lithology content is less than 25%, located in the uppermost layer; 3.3.2) Methods of expressing single lithology: When there is only one lithology, the upper, middle, and lower parts of the entire structural-genetic unit are represented by the same pattern, indicating that the lithology runs throughout the unit; 3.3.3) Two methods of expressing lithology: If there are two lithologies, and one lithology accounts for more than 50%, then that lithology will be repeated throughout the unit; Another way of arranging the lithologies is by their content: If the secondary lithology accounts for 25-50%, it occurs in the middle unit; If the secondary lithology accounts for less than 25%, it occurs in the upper unit; 3.3.4) Three methods of expressing lithology: When there are three lithologies, they occur in the lower, middle, and upper units, according to their contents; 3.3.5) Identification and representation of structural and hydrodynamic conditions: In the structure-genesis unit, the width of the pattern is used to represent the structure and its corresponding hydrodynamic conditions: Low-energy environment: forming limestone carbonate or matrix support structures, represented by narrow patterns, reflecting low energy conditions; Medium-energy environment: carbonate rocks that form medium-grained support structures are represented by patterns of medium width, reflecting a medium-energy environment; High-energy environment: forms bright crystal structure or grain-supported structure, represented by wide patterns, representing deposition in a high-energy environment; 3.3.6) Lithology and structural pattern design: Simple lithology: For a single lithology or a simple lithology combination, a fixed pattern symbol is used to represent it; Complex lithology: For complex lithology combinations, design combination patterns according to lithology content: The main lithology pattern is prominent, and an obvious legend symbol is used; For secondary lithology or lithology with medium content, a second pattern symbol is superimposed on the main lithology pattern to indicate the relative content of the lithology; When there are three lithologies, a combined pattern is added to the main pattern to reflect the proportion of the three lithologies; Special genetic lithology: For special genetic or structural lithology, special pattern symbols are used to represent it; 3.3.7) Thickness representation method. Lithology layers of different thicknesses can be distinguished in the legend by special symbols: Thin layer: indicated by =; Middle layer: indicated by ≠; Thick layer: indicated by #; The above symbols can be combined with pattern designs to indicate changes in thickness of different lithologies.

9. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 8, characterized in that: In step 4, the reservoir space types include framework residual pores, intergranular pores, intragranular dissolved pores, dolomite intercrystalline pores, dissolved pores, and fractures.

10. The method for quantitative geological evaluation of large-scale high-quality carbonate reservoirs according to claim 9, characterized in that: In step five, large-scale reservoir diagenesis includes destructive diagenesis and constructive diagenesis; Destructive diagenesis reduces the porosity and permeability of the reservoir, which has adverse effects on reservoir quality, including cementation, compaction pressure solution and silicification; Constructive diagenesis is beneficial to improving the pore structure of the reservoir and increasing the porosity and permeability of the reservoir, including dissolution, fracturing, dolomitization and recrystallization; The diagenetic sequence analysis can be divided into the following stages: A. Early diagenesis stage Micritization: carbonate particles gradually transform into micrite carbonate, forming framework pores between particles; this helps to form reservoir space; Cementation: Early dolomite fibrous and lamellae cements were formed, which played a role in resisting compaction, but some pores were also filled; B. Middle diagenetic stage Compaction and pressure solution: As the burial depth increases, the compaction effect intensifies, the reservoir porosity begins to decrease, and the pressure solution effect causes the pores between particles to further shrink; Dolomitization: Dolomitization occurs in this stage, intercrystalline pores are generated, and some pore structures are improved; C. Late diagenetic stage Dissolution: In the later stage of burial, the dissolution of fluids is enhanced, forming dissolution pores and improving the porosity of the reservoir; Fracturing: Tectonic movement triggers the development of fractures, increasing the permeability of the reservoir; Effect of hydrocarbon charging: After hydrocarbon charging occurs, the fluid fills the pores, further affecting the porosity and permeability of the reservoir.

Images