Gas Reservoirs Research Articles

The law of fracture propagation and intersection in zipper fracturing of deep shale gas wells

In response to the unclear understanding of fracture propagation and intersection interference in zipper fracturing under the factory development model of deep shale gas wells, a coupled hydro-mechanical model for zipper fracturing considering the influence of natural fracture zones was established based on the finite element – discrete element method. The reliability of the model was verified using experimental data and field monitoring pressure increase data. Taking the deep shale gas reservoir in southern Sichuan as an example, the propagation and interference laws of fracturing fractures under the influence of natural fracture zones with different characteristics were studied. The results show that the large approaching angle fracture zone has a blocking effect on the forward propagation of fracturing fractures and the intersection of inter well fractures. During pump shutdown, hydraulic fractures exhibit continued expansion behavior under net pressure driving. Under high stress difference, as the approaching angle of the fracture zone increases, the response well pressure increase and the total length of the fractured fracture show a trend of first decreasing and then increasing, and first increasing and then decreasing, respectively. Compared to small approach angle fracture zones, natural fracture zones with large approach angles require longer time and have greater difficulty to intersect. The width of fractures and the length of natural fractures are negatively and positively correlated with the response well pressure increase, respectively, and positively and negatively correlated with the time required for intersection, the total length of hydraulic fractures, and fracturing efficiency, respectively. As the displacement distance of the well increases, the probability of fracture intersection decreases, but the regularity between displacement distance and the response well pressure increase and the total length of fractures is not obvious.

A parallel compositional reservoir simulator for large-scale CO2 geological storage modeling and assessment

Storing CO2 in deep aquifers and depleted gas reservoirs is an effective way to achieve carbon neutrality. However, the numerical simulation of CO2 storage in these formations is challenging due to the complexity of gases-brine systems. The number of gas species included in the gases-brine fluid models of existing simulators cannot meet the rapidly evolving CO2 sequestration scenarios. To address this intricate issue, we developed a three-dimensional fully implicit parallel CO2 geological storage simulator (PRSI-CGCS) on distributed-memory computers based on our in-house parallel platform. This simulator uses a compositional fluid model with a diverse range of gas species, including CO2, C1 ~ C3, N2, H2S, as well as newly added gases H2 and O2, which may be encountered in geological CO2 storages. Besides, we provide more suitable scaling factors for different gases in the stability analysis bypassing (SAB) method to accelerate the gases-brine phase equilibrium calculations. PRSI-CGCS does not incorporate energy conservation equations, and salt precipitation or dissolution is also not considered. Numerical experiments show that our simulator is scalable, robust and validated to simulate large-scale CO2 storage problems with hundreds of millions of grid blocks on a parallel supercomputer cluster. Besides, after our modification on scaling factors, the SAB method can reduce the number of stability analyses by 61.39 % to 88.71 %, thereby reducing simulation time. Furthermore, case studies indicate that injecting O2 and H2 along with CO2 reduces the stability or capacity of CO2 storage and increases the pressure required for injection. However, this impact is not significant when the impurity content is less than 10 %.

An improved two-phase rate transient analysis method for multiple communicating multi-fractured horizontal wells in shale gas reservoirs: Field cases study

The reduction in well spacing for multi-fractured horizontal wells (MFHWs) and the increase in infill drilling exacerbate the risk of fracture communication. This presents substantial challenges for the rate transient analysis of the parent–child well system. This study proposes an improved two-phase straight-line analysis method to evaluate the linear flow parameters of multiple communicating MFHWs in shale gas reservoirs. Considering shale gas adsorption–desorption mechanisms, nonuniform length of fractures, stress-dependent effects, and matrix shrinkage effects, two-phase productivity equation is established within the dynamic drainage area (DDA). Subsequently, we develop a three-well square root of time plot based on DDA correction and propose a rigorous workflow for evaluating linear flow parameters in single-well, two-well, and three-well systems. The straight lines on the parent well's square root of the time plot exhibit varying degrees of jumps, depending on the frequency of fracture communication. After communication, it is necessary to adjust the cumulative production and production time of the parent well to accurately recalculate the average pressure within the drainage area. Numerical simulations are employed to generate a series of cases under different reservoir conditions to validate the accuracy of the proposed model. The results show that the model estimates fracture half-lengths with errors within 8%, meeting the precision requirements for field applications. Additionally, the method exceeds numerical simulations in computational speed. Two field case studies in the WY Basin, China, further illustrate the effectiveness and practicality of the proposed method, providing theoretical support for hydraulic fracturing construction design and development planning.

Molecular dynamics of CH4 adsorption and diffusion characteristics through different geometric shale kerogen nanopores

In shale, pore structure plays an extremely significant effect on CH4 storage and transportation in a reservoir, especially for the reservoir involving large amounts of extremely tiny nanopore and variance of microstructure. In this study, three molecular dynamics models for different types of kerogen nanopores such as serration type, arc type and great-wall type are established, validated and implemented to assess the impact of pore structure on CH4 adsorption and diffusion behaviors in kerogen matrix and nanopore at temperature 320 ∼ 380 K, pressure 5 ∼ 20 MPa and pore size 3 ∼ 5 nm. The simulation results demonstrate that the CH4 density in the bulk of serration-type, arc-type and great-wall-type pores is 1.6, 1.3 and 1.9 higher than that inside kerogen molecules. Increasing temperature can weaken the adsorption capacity of kerogen, but the serration-type pore is the most sensitive to temperature. Regardless of the pore type, increasing pressure can significantly enhance the adsorption capacity of kerogen which is almost unaffected by pore size, whereas the CH4 diffusion coefficient increases with pore size. Furthermore, the great-wall-type pore can adsorb more CH4 molecules due to its smooth surface, followed by change in the arc-type and serration-type pores in turn. Among these types of pores, the CH4 diffusion coefficient is the most insensitive to the size of arc-type pore. Hence, the influences of kerogen pore structure under different conditions of temperature, pressure and pore size are quantified in this work to improve a comprehensive understanding of CH4 adsorption and diffusion behaviors in shale, thereby contributing to high-efficient and sustainable development of shale gas reservoirs.

A thermodynamics-based coupled model for multi-phase flowback in deformable dual-porosity shale gas reservoirs

Over the past decades, there has been growing interest in modelling multi-phase flowback in shale gas reservoirs during hydraulic fracturing, primarily due to the significant risk of groundwater pollution. However, the lack of fully coupled simulations and a unified theoretical model has hindered the study of coupled adsorptive hydro-mechanical behaviour and its influence on fluid flowback prediction. In this paper, we have extended the non-equilibrium thermodynamics-based Mixture Coupling Theory to derive the constitutive relationship and governing equation for adsorptive multi-phase fluid flows in deformable dual-porosity media. Helmholtz free energy density has been used to establish the relationship between solids and fluids. The interaction of adsorptive fluids in the pore and fracture space has been fully considered, leading to a new form of constitutive equation, which obtained the molecular adsorptive effect on the rock by introducing adsorption entropy production. The proposed governing equations determine the fully coupled evolution of solid deformation and multi-phase flow, with the consideration of adsorption as well as pore and fracture porosity change. Numerical simulation is then performed to study the flowback of a real shale gas well and the influence of coupled behaviour on model prediction. The simulation shows that the flowback flux is mainly by the fracture (more than 99.9 %) and the overall cumulative volume is 2427.1 m3 within 225 h which accounts for about 5.3 % of the total injected fracturing fluid, and the sensitivity analysis reveals that the manual fracture porosity is the most sensitive factor to the cumulative flowback. This work provides new insights into the flowback process of shale reservoirs in a fully coupled view and the proposed theoretical tool should contribute to the modelling of other adsorptive multi-phase flow problem in deformable dual-porosity media such as carbon storage and coalbed methane production.

Differential Pressure Power Generation in UGS: Operational Optimization Model and Its Implications for Carbon Emission Reduction

Underground Gas Storage (UGS) is an important facility for natural gas peak adjustment and ensuring the balance between energy supply and demand. The daily gas injection and production capacity of large UGS can reach several hundred million or even billions of cubic meters, and the energy consumed by the injection and production equipment is not to be underestimated, which also contains a large amount of pressure energy that can be utilized for power generation. In this context, the optimization of low-carbon operation of UGS is of great practical significance in engineering. In this study, an innovative UGS system operation optimization method is proposed to integrate a natural gas differential pressure generator set in the UGS system. Considering the complex interconnections among multiple storage areas, multiple wells and wellsites, and the hydro-thermodynamic constraints during the operation of injection and production pipeline network, and with the objective of minimizing the carbon emission, the UGS integrated with Differential Pressure Power Generation System (UGSIDPPGS) is established. In order to solve this complex model, this paper designs an optimization solution framework based on variational assignment, which effectively avoids the problem of falling into inferior solutions during the solution process. The optimization model is applied to the case study of a large-scale depleted gas reservoir in China, and the optimal operation schemes under three scenarios are successfully obtained. The results show that the UGSIDPPGS optimization model, not only effectively utilizes the pressure energy, generates up to 56.908×106kW·h per month, and reduces the CO2 emission by 56,738 tons, but also achieves the low-carbon and economic operation of the UGS. In conclusion, the operation strategy proposed in this study is of great value for optimizing the operation of UGS, and provides practical guidance and suggestions for the low carbon and environmental protection of UGS and the utilization of new energy sources.

Analysis of Production Decline Type Curves Considering Water Influx in Naturally Fractured Gas Reservoirs

Abstract In the development of fractured gas reservoirs with edge and bottom water, water invasion is a pervasive issue. However, most production decline analysis models focus on primary depletion with closed boundaries rather than secondary depletion with water influx. Therefore, this paper aims to develop decline type curves for analyzing and interpreting production data from existing natural water influx in fractured gas reservoirs. Firstly, a transient dual porosity flow model is developed considering water influx in naturally fractured gas reservoirs, the functions of Blasingame decline type curves are derived and obtained. Subsequently, the Blasingame production decline type curves of a vertical well in naturally fractured reservoirs experiencing natural water influx are plotted. These new type curves can estimate water invasion and dual medium parameters, offering valuable insights for production decline analysis in fractured reservoirs with water influx. The Blasingame production decline curves are divided into six regimes based on characteristics. Then, the effects of various formation parameters and water invasion cases on the type curves are discussed and analyzed. Compared with Blasingame type curves without water influx at the external boundary, the behaviors of those presented in this paper are quite different at the boundary responses. Finally, through the analysis of a case well, it is found that theoretical type curves considering dual-medium and water invasion are more consistent with actual production data. This suggests that these new type curves provide more accurate estimation for understanding and managing issues related to water invasion in fractured gas reservoirs.

Micro-scale flow simulation study of low-yield wells in tight gas reservoirs

Abstract The mechanism of gas-water flow in reservoirs has traditionally been characterized macroscopically based on flow experiments, but the microscopic mechanisms of gas-water flow in porous media cannot be precisely described experimentally. This paper categorizes low-yield gas wells into Types I, II, and III. With microscopic visualization principles, three different types of core thin-section photos were selected to construct a pore structure model, allowing for micro-scale flow simulation to examine micro-scale percolation patterns in various types of low-yield gas well reservoirs. The results show that there is a shorter displacement time in Type I reservoirs compared to Type II and III reservoirs which exhibit more pronounced fingering phenomena.

On the Significance of Hydrate Formation/Dissociation during CO2 Injection in Depleted Gas Reservoirs

Summary The study aims to quantitatively assess the risk of hydrate formation within the porous formation and its consequences on injectivity during storage of CO2 in depleted gas reservoirs considering low temperatures caused by the Joule-Thomson (JT) effect and hydrate kinetics. Hydrates formed during CO2 storage operation can occupy porous spaces in the reservoir rock, reducing the rock’s permeability and thus becoming a hindrance to the storage project. The aim was to understand which mechanisms can mitigate or prevent the formation of hydrates. The key mechanisms we studied included water dry-out, heat exchange with surrounding rock formation, and capillary pressure. A semicompositional thermal reservoir simulator is used to model the fluid and heat flow of CO2 through a reservoir initially composed of brine and methane. The simulator can model the formation and dissociation of both methane and CO2 hydrates using kinetic reactions. This approach has the advantage of computing the amount of hydrate deposited and estimating its effects on the porosity and permeability alteration. Sensitivity analyses are also carried out to investigate the impact of different parameters and mechanisms on the deposition of hydrates and the injectivity of CO2. Simulation results for a simplified model were verified with results from the literature. The key results of this work are as follows: (1) The JT effect strongly depends on the reservoir permeability and initial pressure and could lead to the formation of hydrates within the porous media even when the injected CO2 temperature was higher than the hydrate equilibrium temperature; (2) the heat gain from underburden and overburden rock formations could prevent hydrates formed at late time; (3) permeability reduction increased the formation of hydrates due to an increased JT cooling; and (4) water dry-out near the wellbore did not prevent hydrate formation. Finally, the role of capillary pressure was quite complex, as it reduced the formation of hydrates in certain cases and increased in other cases. Simulating this process with heat flow and hydrate reactions was also shown to present severe numerical issues. It was critical to select convergence criteria and linear system tolerances to avoid large material balance and numerical errors.

Diffusive nature of different gases in graphite: Implications for gas separation membrane technology

Graphite membranes have gained attention in membrane technology for gas separation due to their high stiffness, strength, and stability in corrosive and high-temperature environments. Graphite exists naturally in geologic media and can also be prepared by synthetic processes. In- situ hydrogen (H2) production in petroleum reservoirs or H2 storage in depleted gas reservoirs results in contamination with CH4 and CO2. To address the separation challenge at the surface, a sustainable downhole wellbore membrane must be available to separate H2, leaving behind CO2 and other gases to improve operational economics. Currently, there are no studies in the literature on the self-diffusivity of gases (CO2, H2, and CH4) in graphite as a function of pore size. To overcome time constraints in diffusivity experiments, this work utilized mathematical models and molecular simulations to delineate the self-diffusivity of gases in graphite of different pore sizes.To acknowledge subsurface operational conditions during in situ hydrogen production, we considered a temperature of 360 K and a wide pressure spectrum from 2 MPa to 20 MPa. In this study, we explored the diffusive nature of H2, CH4, and CO2 gases in different nanopore-sized graphite using analytical and molecular simulation approaches. We validated the results by presenting unrestricted case density calculations. First, effective diffusivity was calculated using the mean free pore path, followed by gas adsorption at high pressures (10–20 MPa) and a temperature of 350 K. The study utilized theoretical models and molecular dynamics (MD) simulations to determine the self-diffusivity of gases in graphite systems with various structures.

Utilization law of shale gas in hydraulic fracturing with the Changning–Weyuan block in China as an example

The process of extracting shale gas, particularly the study of the utilization law of shale reservoirs modified by hydraulic fracturing technology, is crucial for understanding the effective development of shale gas. This understanding can significantly influence the estimated ultimate recovery of reserves. Our study focused on Longmaxi Formation shale in the Changning–Weiyuan block. To investigate the hydraulic fracturing expansion mechanism and utilization law, we employed shale reservoir physical and mechanical characterization, indoor triaxial hydraulic fracturing experiments, and numerical simulations. The findings are as follows. The rupture pressure of hydraulic fractures increases with the peripheral pressure, and high stress is conducive to the formation of internal microfractures. Additionally, a high rate of water injection enhances fracture extensions along the direction of fluid injection. Under varying injection pressures, the length of crack extensions and number of bond damages in shale are positively correlated with the injection pressure. Conversely, under different differential ground stresses, the length of crack extensions and number of bond damages are negatively correlated with the injection pressure. The six main factors affecting the effective utilization of shale gas are as follows: the stimulated reservoir volume, number of hydraulic fracture clusters, fracture length, fracture height, number of fracture stages, and cluster spacing, accounting for 27.13%, 14.74%, 10.31%, 9.58%, 9.53%, and 9.29%, respectively, with a cumulative contribution rate of 80.58%. This study clarifies the hydraulic fracturing mechanisms of shale reservoirs and the laws governing shale gas production, providing technical support for the development of shale gas reservoirs.

A Multiple-physics coupled model for nanoconfined CO2-CH4 mixture transport behavior: Implications for CO2 geological storage in ultra-tight formation

Considerable efforts have been made to examine the feasibility of CO2-enhanced gas recovery (CO2-EGR), a promising approach for improving gas recovery by using CO2 to displace in-situ CH4 in ultra-tight gas reservoirs rich in nanopores. However, most research has focused on either single-component gas flow physics or competitive adsorption of multiple gas components in nanopores. The flow behavior of nanoconfined CO2-CH4 mixtures remains an area of knowledge gap. This work establishes a theoretical framework for CO2-CH4 mixture flow capacity by coupling mixture flow in the bulk region with surface diffusion in the adsorption area. Results indicate that: a) Total mixture flow conductance increases rapidly at pressures below ∼10 MPa, with CO2 contributing over 99 % to surface diffusion conductance; b) Increasing CO2 molar ratio from 0.2 to 0.8 can lead to a 167 % enhancement in total mixture conductance; c) Variations in CO2-CH4 competitive adsorption characteristics have little impact on total conductance.

Understanding the Hydrocarbon Accumulation Process in Deep–ultradeep Oil and Gas Reservoirs in Complex Structural Areas—The Qixia Formation in the Shuangyushi Structure in Northwestern Sichuan Basin, China

Deep-ultradeep oil and gas reservoirs in complex structural areas have typically undergone multistage tectonic processes that have a considerable influence on the hydrocarbon composition, isotopic composition, and other geochemical characteristics of petroleum. By assessing the charging period of hydrocarbon accumulation during a particular age we can determin these changes. We studied the characteristics of fluid inclusions developed in the dolomite reservoir in the Middle Permian Qixia Formation in the Shuangyushi structure of the northwestern Sichuan Basin using methods such as inclusion petrography, microbeam fluorescence fluorescence spectroscopy, and inclusion homogenization temperature. Furthermore, the main peak wavelength of the fluorescence spectrum, red–green ratio/chromatic parameter, Q650/500, as well as the chromatic parameter corresponding to emission flux at 535 nm (QF535) and their correlations with the homogenization temperature distribution, were used to identify the charging period of hydrocarbons in the Qixia Formation. The results show that different types of fluid inclusions were developed in the Qixia Formation. The fluorescence of hydrocarbon inclusions is mainly blue, with a small amount of yellow–green and orange–yellow. The max of orange–yellow, yellow–green, and blue fluorescence of the hydrocarbon inclusions range between 562 ∼ 579 nm, 497 ∼ 548 nm, and 447 ∼ 497 nm, respectively. The distribution of the homogenization temperatures during the same period ranges from 100 °C to 110 °C, from 120 °C to 140 °C, and from 160 °C to 170 °C, respectively. By combining the burial and thermal evolution histories of the Qixia Formation, we concluded that the Qixia Formation has experienced three stages of oil and gas charging, with the time of 204, 185 and 158 Ma. This method is of great significance to determine the date and duration of oil and gas accumulation, and provides technical support for the recovery of ultra-deep hydrocarbon accumulations in complex structural areas.

Oil and gas reservoirs in clinoforms of the Kolgan strata in the Volga–Ural oil and gas province: Forecast and survey technologies

Oil and gas reservoirs in clinoforms of the Kolgan strata in the Volga–Ural oil and gas province: Forecast and survey technologies

PVT-Properties Analysis of Reservoir Gases of the Yurubcheno-Tokhom Oil and Gas Accumulation Zone of the Baikit Oil and Gas Region Based on Regional Trends

PVT-Properties Analysis of Reservoir Gases of the Yurubcheno-Tokhom Oil and Gas Accumulation Zone of the Baikit Oil and Gas Region Based on Regional Trends

Oolitic Sedimentary Characteristics of the Upper Paleozoic Bauxite Series in the Eastern Ordos Basin and Its Significance for Oil and Gas Reservoirs

In recent years, great breakthroughs have been made in gas explorations of the Upper Paleozoic bauxite series in the Longdong area of the Ordos Basin, challenging the understanding that bauxite is not an effective reservoir. Moreover, studying the reservoir characteristics of bauxite is crucial for oil and gas exploration. Taking the bauxite series in the Longdong area as an example, this study systematically collects data from previous publications and analyzes the petrology, mineralogy, oolitic micro-morphology, chemical composition, and other sedimentary characteristics of the bauxite series in the study area using field outcrops, core observations, rock slices, cast slices, X-ray diffraction analysis, scanning electron microscopy and energy spectra, and so on. In this study, the oolitic microscopic characteristics of the bauxite reservoir and the significance of oil and gas reservoirs are described. The results show that the main minerals in the bauxite reservoir are boehmite and clay minerals composed of 73.5–96.5% boehmite, with an average of 90.82%. The rocks are mainly bauxitic mudstone and bauxite. A large number of oolites are observable in the bauxite series, and corrosion pores and intercrystalline pores about 8–20 μm in size have generally developed. These pores are important storage spaces in the reservoir. The brittleness index of the bauxite series was found to be as high as 99.3%, which is conducive to subsequent mining and fracturing. The main gas source rocks of oolitic bauxite rock and the Paleozoic gas series are the coal measure source rocks of the Upper Paleozoic. The oolitic bauxite reservoirs in the study area generally have obvious gas content, but the continuity of the planar distribution of the bauxite reservoirs is poor, providing a scientific basis for studying bauxite reservoirs and improving the exploratory effects of bauxite gas reservoirs.

Review of Reservoir Damage Mechanisms Induced by Working Fluids and the Design Principles of Reservoir Protection Fluids: From Oil–Gas Reservoirs to Geothermal Reservoirs

Various working fluids are applied during geothermal reservoir development, and geothermal reservoir damage induced by contacts between working fluids and reservoir formations are inevitable. Reservoir damage mechanisms, including solid and colloidal plugging, fluid sensitivity, stress sensitivity, and water locking, provide guidance for designing reservoir protection working fluids. In this paper, based on the design principles of reservoir protection working fluids applied in oil–gas reservoirs, four design principles of reservoir protection working fluids are proposed to eliminate potential geothermal reservoir damage for geothermal reservoirs, containing solid-free, facilitated flowback, temporary plugging, and inhibition. Solid-free is achieved by replacing solids with polymers in working fluids. Surfactant and materials with low affinity towards rock surfaces are applied for the facilitated flowback of working fluids from reservoir formations. Temporary plugging is achieved by using temporary plugging materials, some of which are polymers that also apply to solid-free working fluids. Besides, some of the temporary plugging materials, such as surfactant, are applicable for both the facilitated flowback and inhibition of working fluids. The inhibition of working fluids include the inhibition of clay minerals, which can be attributed to clay mineral inhibitors or activity regulators in working fluids, as well as the inhibition of mineral precipitations. This review aims to provide insights for geothermal reservoir protection working fluids, contributing to achieving an efficient development of geothermal resources.

A geothermal doublet in a single well: application of the recirculation well concept to reuse wells to be abandoned

The depletion of oil and gas reservoirs leaves many deep and expensive wells with no option but to be abandoned. However, these wells could have a second chance to extend their life as a source of geothermal energy, especially if they are located next to urban or industrial areas in need of heating. This article shows a technical analysis of the well recirculation or geothermal doublet in a single well approach as a strategy to reuse wells that cross aquifers. Different aspects of this strategy are highlighted, including the technical conditions required for the application, the well completion, and the geothermal performance. The latest is assessed via numerical reservoir simulations using geological data from an existing well. The results show that vertical petrophysical heterogeneities play an important role in the performance and feasibility of this approach.

A Numerical Investigation on Kick Control with the Displacement Kill Method during a Well Test in a Deep-Water Gas Reservoir: A Case Study

A Numerical Investigation on Kick Control with the Displacement Kill Method during a Well Test in a Deep-Water Gas Reservoir: A Case Study

Unsupervised Machine Learning-Based Singularity Models: A Case Study of the Taiwan Strait Basin

The identification of geochemical anomalies in oil and gas indicators is a fundamental task in oil and gas exploration, as the process of oil and gas accumulation is a low probability event. Machine learning algorithms for anomaly detection are applicable to the identification of oil and gas geochemical anomalies related to oil and gas accumulation. However, when using oil and gas indicators for anomaly detection, the diversity of these indicators often leads to the influence of the indicator redundancy on the identification of such features. Therefore, it is particularly important to select appropriate oil and gas indicators for anomaly detection. In this study, a hybrid model combining unsupervised machine learning methods and singularity analysis methods was used to evaluate oil and gas indicator anomalies using geochemical data from the Taiwan Strait Basin. The models used in this study include the singularity index model (LSP), the principal component model combined with the singularity index model (PCA and LSP), and the cluster analysis combined with the principal component model and the singularity index model (CLA-PCA-LSP). PCA models can reduce the dimensions of the data and retain as much information as possible. CLA divides data samples into different groups, so that samples within the same group are more similar and samples between different groups are less similar. LSP is mainly used for measuring the setting and singular degree of local anomalies in multi-scale geochemistry, geophysics, and other types of local anomalies, and it has a unique advantage in extracting low and weak anomalies and nonlinear characteristics. The results of the study show that the results obtained using the CLA-PCA-LSP hybrid model are very similar to those obtained by performing PCA on the entire index and then calculating the singularity index. This also verifies that, for the study areas of the Jiulongjiang Depression and Jinjiang Depression, we can select oil and gas indicators that are favorable for exploration analysis, without including all indicators in the analysis scope, thereby improving the computational efficiency. The application of a singularity analysis method and generalized self-similarity principle in extracting the geochemical information of oil and gas indicators in the Taiwan Strait Basin highlights key technologies such as the identification of weak anomalies, decomposition of composite anomalies, and integration of spatial information. The combination anomalies delineated by the singularity analysis method and S-A method not only reflect the spatial relationship with known oil and gas reservoir distribution, but also show the multiple combination anomalies in unknown areas, providing favorable guidance for the next exploration direction in the Taiwan Strait Basin.