Prediction method for fracture-vuggy carbonate reservoir under salt

Abstract

The invention discloses an under-salt fracture-vuggy carbonate reservoir prediction method, and relates to the technical field of petroleum geological exploration, and the method comprises the following steps: S1, obtaining three-dimensional earthquake fine interpretation and horizon calibration of a research area, and building a stratigraphic framework; s2, fault / crack fine interpretation, fault / crack classification and classification identification are carried out, and a crack network is constructed; s3, the sedimentary facies type with the relative advantages is recognized on the basis of the compact carbonate rock, and the ancient landform is restored; s4, reservoir main control factors are analyzed, and an under-salt fracture-cavity body carbonate reservoir development mode is established; s5, under-salt fracture-vuggy reservoir prediction, the problems that in the prior art, reservoir prediction difficulty is large, and the target exploration success rate is low are solved, identification of fracture-vuggy reservoirs formed by carbonate rocks with compact matrix lithology under fracture dissolution transformation is particularly facilitated, and favorable development areas of the fracture-vuggy carbonate rocks are predicted.

Description

Technical Field

[0001] The invention relates to the technical field of petroleum geological exploration, and in particular to a method for predicting sub-salt fracture-cavity carbonate reservoirs. Background Art

[0002] Among the proven oil and gas reserves in the world, evaporites are developed in many large basins in the world's famous oil and gas-rich areas such as the Middle East, Central Asia, and North America. According to technical research, due to the influence of extremely thick salt rocks, the subsalt structure is poorly implemented, reservoir prediction is difficult, and the success rate of target exploration is not high.

[0003] In the prior art, the relevant documents disclosed in the technology of prediction of subsalt carbonate reservoirs include: such as the publication number "CN113109875A" published on July 13, 2021, entitled "A method for inversion of subsalt carbonate reservoirs under full waveform velocity field constraints", the publication number "CN111983683A" published on November 24, 2020, entitled "A method and system for predicting subsalt lacustrine limestone reservoirs under few well conditions", the publication number "CN110211226A" published on September 6, 2019, entitled "A method for interpreting the structure of deep-water subsalt carbonate reservoirs", and the publication number "CN110068862A" published on July 30, 2019, entitled "A method and device for predicting high-quality reservoirs in subsalt ultra-deep fault anticline oil and gas reservoirs".

[0004] The literature on the prediction of subsalt carbonate reservoirs includes: Hao Jinjin, He Weiwei, Zhang Yajun, etc. took the Amu Darya BP gas field as an example, and used layer flattening, phase conversion and inversion techniques to qualitatively and quantitatively characterize the reflection characteristics and reservoir thickness of the subsalt reef-shoal reservoir (2020); Shan Tianyou took the Brazilian deep-water subsalt carbonate rocks as the research object, combined high-precision post-stack seismic phase-controlled reservoir inversion with pre-stack exact equation fluid inversion to predict the spatial distribution of subsalt bioherm reservoirs and fluids (2019); Tian Yu, Zhang Xingyang, Zhu Guowei, etc. took the Amu Darya Callovian Oxfordian as the research background, and found that reefs often develop under salt domes, which are important drilling targets. At the same time, the distribution of gypsum salt rocks has a significant control on oil and gas migration and enrichment (2016); Yang Xiaolin conducted research on the subsalt fractured carbonate reservoirs in the eastern piedmont thrust belt on the right bank of the Amu Darya River, clarified the development patterns of bioherms and fractures in the area, and identified the distribution of reefs through seismic attribute data , and finally accurately portrayed the high-quality carbonate reservoirs under the thrust belt by inverting the impedance body (2013); Wang Ling, Zhang Yan, Ma Xiaoyu, etc. took the Amu Darya Basin as an example to analyze the seismic response characteristics of different reefs and gypsum salt rocks, and optimized the sequence framework constrained sparse inversion method to effectively eliminate the influence of gypsum salt rock deformation on the prediction of reef reservoirs (2010); He Xiaosong, Sun Lin, Zhang Hongbin, etc. started from the seismic reflection characteristics of reefs in the carbonate rock layer in Block A of Central Asia, and analyzed the seismic reflection characteristics of reefs in the carbonate rock layer, confirming the oil and gas target area in the reef construction development zone (2009); Aikebai Shadik conducted a comprehensive evaluation of the subsalt carbonate reservoirs in the Tahe Oilfield, studied the paleokarst and reservoir development laws of the Ordovician carbonate rocks in the salt body coverage area, and comprehensively adopted amplitude extraction technology, amplitude change rate analysis technology, fine coherence analysis (fault and fracture zone prediction), favorable reservoir seismic reflection pattern analysis and other technologies to predict reef beach reservoirs (2006).

[0005] The research results of the above patent application documents and journal documents show that the combination of biological reefs and overlying gypsum salt rocks is easy to form structural-lithological composite closures, so the prediction of subsalt carbonate reservoirs is mostly concentrated on the distribution and characterization of reef bodies. However, with the increase in the exploration and development of gas fields, some carbonate rocks with dense matrix lithology can also form fracture-cavity reservoirs under the transformation of fracture dissolution, which is a favorable exploration target. However, there is currently no prediction method for such reservoirs. This method conducts research on dense carbonate rocks, takes fracture identification and prediction as the core, establishes a fracture-cavity carbonate rock development model, and provides a method for predicting subsalt fracture-cavity reservoirs. Summary of the invention

[0006] The purpose of the present invention is to provide a method for predicting fracture-cavity carbonate reservoirs under salt, so as to solve the problems of great difficulty in reservoir prediction and low success rate of target exploration in the prior art, and is particularly beneficial to the prediction of fracture-cavity reservoirs formed by some carbonate rocks with relatively dense matrix lithology under fracture dissolution transformation.

[0007] The present invention is achieved through the following technical solutions: A method for predicting subsalt fracture-cavity carbonate reservoirs comprises the following steps: S1. Obtain detailed 3D seismic interpretation and horizon calibration in the study area and build a stratigraphic framework; S2. Detailed interpretation of faults / fractures, classification and hierarchical identification of faults / fractures, and construction of fracture networks; S3. Identify the relatively dominant sedimentary facies types based on dense carbonate rocks and restore the paleo-geomorphology; S4. Analyze the main controlling factors of the reservoir and establish the development model of the sub-salt fracture-cavity carbonate reservoir; S5. Prediction of subsalt fracture-cavity reservoirs.

[0008] Furthermore, in step S1, the method for constructing the stratum grid is: S1-1: Acquire seismic data in the study area, perform target processing, improve the signal-to-noise ratio, and improve seismic imaging effects; S1-2: Combine drilling information to perform time-depth calibration and accurately determine the isochronous interface, which includes the top and bottom interfaces of gypsum-salt rock, the top surface of carbonate rock and the top surface of basement; S1-3: Use isochronous interfaces to construct a stratigraphic framework.

[0009] Furthermore, in step S2, the method for classifying and grading faults and cracks is as follows: S2-1: Combine structural interpretation to identify faults, summarize and classify fault elements, where primary faults control structural belts, secondary faults control the distribution and morphology of traps, and tertiary faults affect the density of fracture development in reservoirs; S2-2: Analyze the fracture properties by combining core and imaging logging data; S2-3: Use seismic data to extract fracture-related attributes, focus on areas prone to fault development, and construct a fracture network.

[0010] Furthermore, in step S2-2, the fracture properties are analyzed including the occurrence, stage and cause of the fractures.

[0011] Furthermore, in step S2-3, the region prone to developing faults includes the stress compression zone, the stress conversion zone and the anticline axis.

[0012] Furthermore, in step S3, the method of identifying the relatively dominant sedimentary facies type and restoring the paleo-geomorphology is as follows: S3-1: Using core and thin section data, the sedimentary facies type was determined based on petrological and paleontological signs. The overall water energy of the Callovian-Oxfordian Stage on the right bank of the Amu Darya was low, and mound-shoal bodies were locally developed on a gentle slope background. S3-2: Summarize the seismic reflection structures corresponding to different sedimentary types, and use relevant seismic attributes to characterize the distribution of beach bodies. The beach phase is a beach-like weak amplitude, weak continuity, chaotic reflection structure, the gentle slope inter-dune marine phase is a sheet-like weak amplitude, medium-strong continuity, parallel reflection structure, and the overlying gypsum salt rock is a strong amplitude, strong continuity, "eyeball" reflection structure; S3-3: The distribution range of the mound-beach body is predicted by combining the configuration relationship between the gypsum-salt rock morphology and the mound-beach body. The areas between the "eyeball" gypsum-salt rocks are mostly favorable areas for the development of mound-beach bodies. S3-4: The layer flattens the top boundary of the salt-gypsum rock and restores the ancient landform during the carbonate rock deposition period.

[0013] Furthermore, in step S4, the method for establishing the sub-salt fracture-cavity carbonate reservoir development model is: S4-1: Analysis of the configuration relationship between fractures and fracture-cavity reservoirs in different periods, among which the structural fractures in the Yanshanian period are the main seepage channels for dissolution fluids; S4-2: Analyze the relationship between different stages of dissolution and the configuration of fracture-cavity reservoirs, among which the acidic fluid during the burial period is the dominant dissolution; S4-3: Analyze the configuration relationship between different sedimentary facies and fracture-cavity reservoirs. If the fracture development zone happens to overlap with the mound-shoal sedimentary microfacies, the fracture-cavity reservoir will be the most developed. S4-4: Based on steps S4-1, S4-2, and S4-3, a fracture-cavity reservoir development model is established, and the reservoir types are divided into dense transformation type and hill-shoal transformation type.

[0014] Furthermore, in step S4-2, the acidic fluid includes organic acid fluid and hydrothermal fluid.

[0015] Furthermore, in step S5, the subsalt fracture-cavity reservoir prediction method is: S5-1: Fracture prediction, using multiple attributes to characterize fracture connectivity; S5-2: Look for possible concealed anticlines under the salt. The axis of the anticline structure is prone to more fractures due to the influence of compression stress. S5-3: Predict the distribution of matrix reservoirs, combine paleo-geomorphological features, and use seismic inversion to characterize the distribution of mound-shoal bodies; S5-4: Based on steps S5-1, S5-2, and S5-3, multiple factors are superimposed to predict the distribution of subsalt fracture-vuggy reservoirs. Fractures are well developed in the anticline axis close to the fault, and the acidic fluid has a strong dissolution and transformation effect on the matrix reservoir, forming a dense transformed fracture-vuggy reservoir. If the hill-beach phase is superimposed, the scale of the fractures and caves will be larger, forming a hill-beach transformed fracture-vuggy reservoir.

[0016] Furthermore, in step S5-1, the attributes include coherence, illumination volume, likelihood volume, and discontinuity.

[0017] Compared with the prior art, the present invention has the following advantages and beneficial effects: 1. In the present invention, the method for predicting subsalt fracture-cave carbonate reservoirs can be used to guide the prediction of subsalt fracture-cave carbonate reservoirs in the Caspian Basin and the Amu Darya Basin overseas, and in the Ordos Basin and the Tarim Basin in China. It has certain guiding significance for finding fracture-cave carbonate rocks with denser lithology under salt or structural-lithological composite closures related to biohumps and beaches, and can reduce drilling risks and improve the accuracy of reservoir prediction.

[0018] 2. In the present invention, this method is based on the clarification of the regional geological background of the study area, combined with seismic data, drilling and logging data, and core thin section data for research. In order to solve the problem that the thick salt-gypsum rock overlying the target layer affects the imaging, seismic processing is carried out. Time-depth calibration is carried out using actual drilling, and an isochronous stratigraphic framework is established. Faults and fractures are precisely identified, and faults are classified and graded to determine the occurrence, stage, and cause of fractures, and to construct a fracture network. Core and thin section data are used to determine the sedimentary phase type of the target layer in the study area, summarize the seismic reflection structure of different sedimentary phase types, and identify the dominant sedimentary phase based on the restoration of paleo-geomorphology by combining the configuration relationship between gypsum-salt rock and dominant sedimentary phases. The relationship between fractures of different stages, dissolution in different periods, and different sedimentary phases and fracture-cavity reservoirs is analyzed to clarify the main controlling factors of reservoir development. Finally, the distribution of subsalt fracture-cavity carbonate reservoirs is predicted by combining the distribution of hilly beach bodies, the current anticline axis, and the fracture development area. BRIEF DESCRIPTION OF THE DRAWINGS

[0019] Figure 1 It is a roadmap for the prediction method of sub-salt fracture-vuggy carbonate reservoirs in the present invention. DETAILED DESCRIPTION

[0020] The present invention is further described in detail below in conjunction with examples, but the embodiments of the present invention are not limited thereto.

[0021] In the present invention, the prediction of subsalt fracture-cave carbonate reservoirs is centered on fractures. In addition to conventional coherence, illumination and other conventional attribute methods, geological knowledge is added to the fracture identification process, and research on such fracture-prone development areas as stress compression zones, stress conversion zones, and structural anticline axes under tectonic backgrounds is carried out to establish a fracture network. At the same time, a mound-shoal body identification technology is created. The mound-shoal body is different from the reef-shoal body, has a small thickness, and is difficult to predict. After using core and logging data to determine the sedimentary microfacies type of the mound-shoal body, the seismic reflection structure of the mound-shoal body is summarized, and the distribution characteristics of the matrix reservoir of the mound-shoal body are comprehensively predicted in combination with the morphology of the overlying gypsum-salt rock. In addition, a subsalt fracture-cave reservoir development model is established, and a fracture-cave gas reservoir development model is established based on the understanding of the mechanism of fractures and dissolution. The fracture development area is superimposed on the dominant mound-shoal phase to predict the favorable reservoir development area. To facilitate the public to understand this scheme, this scheme is further explained in conjunction with specific embodiments below.

[0022] Example 1 This example takes a gas field as an example to further illustrate the prediction method of subsalt fracture-cavity carbonate reservoirs. The main production layer of the gas field is a set of fracture-cavity carbonate rocks, which are covered by nearly one thousand meters of gypsum salt rock, resulting in weak reflection of seismic data and blurred reservoir response characteristics on the seismic profile. Combining existing research results and literature research, it is found that the gas field is subjected to plate compression stress and strong lateral rotation compression, resulting in strong deformation, mainly in the form of high-amplitude fault anticlines. Reference Figure 1 The prediction method of subsalt fracture-cavity carbonate reservoir includes the following steps: Step 1: Based on the regional geological background, well logging data, core slice data and seismic data of the study area, obtain the 3D seismic detailed interpretation and horizon calibration of the study area and build a stratigraphic framework S1-1. Obtain seismic data of the gas field study area, perform target processing on the gas field, improve the signal-to-noise ratio, make the carbonate top surface imaging clearer, make the carbonate inner reflection characteristics more reasonable, and significantly improve the deep imaging effect; S1-2: Combine drilling information to perform time-depth calibration and accurately determine the isochronous interface, which includes the top and bottom interfaces of gypsum-salt rock, the top surface of carbonate rock and the top surface of basement; S1-3: Use isochronous interfaces to construct a stratigraphic framework.

[0023] Step 2: Detailed interpretation of faults / fractures, classification and classification of faults / fractures, and construction of fracture network S2-1: Combine structural interpretation to identify faults, summarize and classify fault elements, where primary faults control structural belts, secondary faults control the distribution and morphology of traps, and tertiary faults affect the density of fracture development in reservoirs; S2-2: Combine core and imaging logging data to analyze the properties of fractures, including the occurrence, stage and cause of fractures; S2-3: Extract fracture-related attributes using seismic data, focus on areas prone to fault development, and construct a fracture network. The areas prone to fault development include stress compression areas, stress conversion areas, and anticline axes.

[0024] According to the above method, the faults with high reliability are finely identified and multiple faults are interpreted. The faults are mainly in the near north-south direction. Vertical fractures and high-angle oblique fractures are developed in the area close to the main fault, while the vertical fractures are less developed in the area far from the main fault, and low-angle fractures are the main ones.

[0025] There are three stages of cracks in the study area: the first stage is invalid cracks, the second stage is dissolution expansion cracks, which are easy to produce high yields, and the third stage is structural cracks, which can produce high yields when paired with high-quality reservoirs. The first stage of pressure solution cracks are completely filled with calcite and are invalid cracks. This group of cracks is numerous and has complex causes, mostly the earliest diagenetic cracks, pressure solution filling cracks, etc. The second stage of superimposed structural cracks are mainly dissolution expansion cracks, mostly high-angle or vertical cracks. Dissolution expansion is common along both sides of the crack surface, forming a dissolution zone with very developed pores, which can be a good storage and seepage section. The third stage of structural cracks is mainly high-angle cracks, and oblique cracks and a small number of horizontal cracks are also developed. The cracks are in a cutting relationship with the karst pore system and have no genetic connection. Most of them are unfilled, and they form good reservoirs when paired with matrix dissolution pores, which can greatly increase oil and gas production.

[0026] Step 3: Identify the relatively dominant sedimentary facies type based on dense carbonate rocks and restore the paleo-geomorphology S3-1: Using core and thin section data, the sedimentary facies type was determined based on petrological and paleontological signs. The overall water energy of the Callovian-Oxfordian Stage on the right bank of the Amu Darya was low, and mound-shoal bodies were locally developed on a gentle slope background. S3-2: Summarize the seismic reflection structures corresponding to different sedimentary types, and use relevant seismic attributes to characterize the distribution of beach bodies. The beach phase is a beach-like weak amplitude, weak continuity, chaotic reflection structure, the gentle slope inter-dune marine phase is a sheet-like weak amplitude, medium-strong continuity, parallel reflection structure, and the overlying gypsum salt rock is a strong amplitude, strong continuity, "eyeball" reflection structure; S3-3: The distribution range of the mound-beach body is predicted by combining the configuration relationship between the gypsum-salt rock morphology and the mound-beach body. The areas between the "eyeball" gypsum-salt rocks are mostly favorable areas for the development of mound-beach bodies. S3-4: The layer flattens the top boundary of the salt-gypsum rock and restores the ancient landform during the carbonate rock deposition period.

[0027] According to the above method, the target layer of the gas field is mainly composed of bioclastic and algae-mass micrite limestone, with deep water bodies, which is a quiet inter-dune marine sedimentary microfacies. In some areas, bioclastic sandstone, composite granular limestone, spherulite limestone, algae-mass spherulite limestone and other granular limestones are deposited, which are bio-mound-beach sedimentary microfacies with relatively strong water energy. Among them, the mound-beach phase is a beach-like weak amplitude, weak continuity, chaotic reflection structure, the gentle slope inter-dune marine phase is a sheet-like weak amplitude, medium-strong continuity, parallel reflection structure, and the overlying gypsum-salt rock is a strong amplitude, strong continuity "eyeball" reflection structure.

[0028] Step 4: Analyze the main controlling factors of the reservoir and establish the development model of subsalt fracture-cavity carbonate reservoir S4-1: Analysis of the configuration relationship between fractures and fracture-cavity reservoirs in different periods, among which the structural fractures in the Yanshanian period are the main seepage channels for dissolution fluids; S4-2: Analyze the relationship between different periods of dissolution and the configuration of fracture-cavity reservoirs, among which the acidic fluid in the burial period is the dominant dissolution, and the acidic fluid includes organic acid fluid and hydrothermal fluid; S4-3: Analyze the configuration relationship between different sedimentary facies and fracture-cavity reservoirs. If the fracture development zone happens to overlap with the mound-shoal sedimentary microfacies, the fracture-cavity reservoir will be the most developed. S4-4: Based on steps S4-1, S4-2, and S4-3, a fracture-cavity reservoir development model is established, and the reservoir types are divided into dense transformation type and hill-shoal transformation type.

[0029] The above method shows that the dissolution of the target layer of the gas field is divided into two stages. The geothermal range of the first stage dissolution window is approximately 80-120℃, and it is later filled with calcite. The geothermal range of the second stage dissolution window is approximately 120-160℃, and CO2, H2S and organic acid fluids dissolve. Among them, the second stage dissolution, i.e. acidic fluid dissolution, is the key to the formation of dissolution pores, and the fault system affects the scope of dissolution.

[0030] The development of reservoirs in the study area is jointly affected by sedimentation, structure and dissolution. During the sedimentary period, the gas field was in a lower gentle slope-outer gentle slope environment, with local development of hilly beach sediments, underdeveloped matrix reservoirs as a whole, and few residual primary pores. The first-stage structural compression accompanied the formation of the second-stage cracks, which is the key geological effect for the formation of large-scale reservoirs. Acidic fluids (organic acid fluids, hydrothermal fluids, TSR reactions) enter the dissolution transformation along the thrust faults and their associated cracks to form dissolution reservoirs. In the second stage of compression, the subsalt basement activated and uplifted to form the third stage of cracks, which superimposed and transformed the early fracture-cavity system, which is conducive to the formation of high-quality reservoirs. The reservoir development model is a strong compression period, with a large number of cracks developed in the anticline axis formed by the thrust fault zone, and the dissolution fluid formed fracture-cavity reservoirs along the thrust fault zone and dissolution.

[0031] Step 5: Prediction of subsalt fracture-cavity reservoirs S5-1: Crack prediction, using multiple attributes to characterize the crack connectivity, including coherence, illumination, likelihood, and discontinuity; S5-2: Look for possible concealed anticlines under the salt. The axis of the anticline structure is prone to more fractures due to the influence of compression stress. S5-3: Predict the distribution of matrix reservoirs, combine paleo-geomorphological features, and use seismic inversion to characterize the distribution of mound-shoal bodies; S5-4: Based on steps S5-1, S5-2, and S5-3, multiple factors are superimposed to predict the distribution of subsalt fracture-vuggy reservoirs. Fractures are well developed in the anticline axis close to the fault, and the acidic fluid has a strong dissolution and transformation effect on the matrix reservoir, forming a dense transformed fracture-vuggy reservoir. If the hill-beach phase is superimposed, the scale of the fractures and caves will be larger, forming a hill-beach transformed fracture-vuggy reservoir.

[0032] Finally, multiple attributes are used to characterize fracture connectivity, including coherence, illumination, likelihood, discontinuity, etc. The potential concealed anticlines under the salt are sought. The axis of the anticline structure is prone to more fractures due to the influence of compression stress. The distribution of matrix reservoirs is predicted, and the distribution of mound-shoal bodies is characterized by seismic inversion in combination with paleo-geomorphic features. The distribution of fracture-cave reservoirs under the salt is predicted by superposition of multiple factors, and the favorable development area of ​​fracture-cave hydrochloric acid rock is determined.

[0033] The above description is only a preferred embodiment of the present invention and does not limit the present invention in any form. Any simple modification or equivalent change made to the above embodiment based on the technical essence of the present invention shall fall within the protection scope of the present invention.

Claims

1. A method for predicting subsalt fracture-cavity carbonate reservoirs, characterized in that: The steps include: S1. Obtain detailed 3D seismic interpretation and horizon calibration in the study area and build a stratigraphic framework; S2. Detailed interpretation of faults / fractures, classification and hierarchical identification of faults / fractures, and construction of fracture networks; S3. Identify the relatively dominant sedimentary facies types based on dense carbonate rocks and restore the paleo-geomorphology; S4. Analyze the main controlling factors of the reservoir and establish the development model of the sub-salt fracture-cavity carbonate reservoir; S5. Prediction of subsalt fracture-cavity reservoirs.

2. A method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 1, characterized in that: In step S1, the method of constructing the stratum grid is: S1-1: Acquire seismic data in the study area, perform target processing, improve the signal-to-noise ratio, and improve seismic imaging effects; S1-2: Combine drilling information to perform time-depth calibration and accurately determine the isochronous interface, which includes the top and bottom interfaces of gypsum-salt rock, the top surface of carbonate rock and the top surface of basement; S1-3: Use isochronous interfaces to construct a stratigraphic framework.

3. A method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 1, characterized in that: In step S2, the method for classifying and grading fault fractures is as follows: S2-1: Combine structural interpretation to identify faults, summarize and classify fault elements, where primary faults control structural belts, secondary faults control the distribution and morphology of traps, and tertiary faults affect the density of fracture development in reservoirs; S2-2: Analyze the fracture properties by combining core and imaging logging data; S2-3: Use seismic data to extract fracture-related attributes, focus on areas prone to fault development, and construct a fracture network.

4. A method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 3, characterized in that: In step S2-2, the properties of the cracks are analyzed, including the occurrence, stage, and cause of the cracks.

5. A method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 3, characterized in that: In step S2-3, the areas prone to developing faults include stress compression areas, stress conversion areas and anticline axes.

6. A method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 1, characterized in that: In step S3, the method of identifying the relatively dominant sedimentary facies type and restoring the paleo-geomorphology is as follows: S3-1: Using core and thin section data, the sedimentary facies type was determined based on petrological and paleontological signs. The overall water energy of the Callovian-Oxfordian Stage on the right bank of the Amu Darya was low, and mound-shoal bodies were locally developed on a gentle slope background. S3-2: Summarize the seismic reflection structures corresponding to different sedimentary types, and use relevant seismic attributes to characterize the distribution of beach bodies. The beach phase is a beach-like weak amplitude, weak continuity, chaotic reflection structure, the gentle slope inter-dune marine phase is a sheet-like weak amplitude, medium-strong continuity, parallel reflection structure, and the overlying gypsum salt rock is a strong amplitude, strong continuity, "eyeball" reflection structure; S3-3: The distribution range of the mound-beach body is predicted by combining the configuration relationship between the gypsum-salt rock morphology and the mound-beach body. The areas between the "eyeball" gypsum-salt rocks are mostly favorable areas for the development of mound-beach bodies. S3-4: The layer flattens the top boundary of the salt-gypsum rock and restores the ancient landform during the carbonate rock deposition period.

7. The method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 1, characterized in that: In step S4, the method for establishing the sub-salt fracture-cavity carbonate reservoir development model is: S4-1: Analysis of the configuration relationship between fractures and fracture-cavity reservoirs in different periods, among which the structural fractures in the Yanshanian period are the main seepage channels for dissolution fluids; S4-2: Analyze the relationship between different stages of dissolution and the configuration of fracture-cavity reservoirs, among which the acidic fluid during the burial period is the dominant dissolution; S4-3: Analyze the configuration relationship between different sedimentary facies and fracture-cavity reservoirs. If the fracture development zone happens to overlap with the mound-shoal sedimentary microfacies, the fracture-cavity reservoir will be the most developed. S4-4: Based on steps S4-1, S4-2, and S4-3, a fracture-cavity reservoir development model is established, and the reservoir types are divided into dense transformation type and hill-shoal transformation type.

8. A method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 7, characterized in that: In step S4-2, the acidic fluid includes organic acid fluid and hydrothermal fluid.

9. The method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 1, characterized in that: In step S5, the subsalt fracture-cavity reservoir prediction method is: S5-1: Fracture prediction, using multiple attributes to characterize fracture connectivity; S5-2: Look for possible concealed anticlines under the salt. The axis of the anticline structure is prone to more fractures due to the influence of compression stress. S5-3: Predict the distribution of matrix reservoirs, combine paleo-geomorphological features, and use seismic inversion to characterize the distribution of mound-shoal bodies; S5-4: Based on steps S5-1, S5-2, and S5-3, multiple factors are superimposed to predict the distribution of subsalt fracture-vuggy reservoirs. Fractures are well developed in the anticline axis close to the fault, and the acidic fluid has a strong dissolution and transformation effect on the matrix reservoir, forming a dense transformed fracture-vuggy reservoir. If the hill-beach phase is superimposed, the scale of the fractures and caves will be larger, forming a hill-beach transformed fracture-vuggy reservoir.

10. A method for predicting subsalt fracture-vuggy carbonate reservoirs according to claim 9, characterized in that: In step S5-1, the attributes include coherence, illumination volume, likelihood volume, and discontinuity.

Images