Search

Marine oil exploration is important yet greatly increases the risk of oil leakage, which will result in severe environment pollution and economic losses. It is an urgent need to develop effective underoil adhesives. However, realizing underoil adhesion is even harder than those underwater, due to the stubborn attachment of a highly viscous oil layer on target surface. Here, inspired by endocytosis, a tough gel tape composed of zwitterionic polymer network and zwitterionic surfactants is developed. The amphiphilic surfactants can form micelle to capture the oil droplets and transport them from the interface to gel via electrostatic attraction of polymer backbone, mimicking the endocytosis and achieving robust underoil adhesion. Benefiting from the oil‐resistance of polymer backbone, the gel further realizes a combination of i) long‐term adhesion with high durability, ii) repeated adhesion in oil, and iii) renewable adhesion efficiency after exhausted use. The tape exhibits an ultra‐high adhesive toughness of 2446.86 J m−2 to stainless steel in silicone oil after 30 days' oil‐exposure; such value of adhesive toughness surpasses many of those achieved in underwater adhesion and is greater than underoil adhesion performance of commercial tape. The strategy illustrated here will motivate the design of sustainable and efficient adhesives for wet environments. [ABSTRACT FROM AUTHOR]

Introduction: With the continuous development of exploration and development, tight sandstone reservoirs have become an essential field of oil and gas exploration. The tight sandstone reservoirs are characterized by complex lithology, poor pore structure, and strong heterogeneity, which bring great difficulties to formation evaluation by well logs. Especially, the accuracy of the Archie formula for calculating the water saturation of tight sandstone reservoirs containing fractures is not high, saturation evaluation faces greater challenges. Therefore, how to calculate the saturation of tight sandstone reservoirs more accurately is an urgent problem to be solved. Methods: In this paper, the tight sandstone reservoirs of the Jurassic Ahe Formation in the Tarim Basin were taken as the research area. A saturation model that combines the effects of shale and fractures was proposed. Specifically, if the shale content is more than 20%, the Indonesian formula is used to calculate the saturation. If the shale content is less than 20%, the dual porosity model is adopted. Based on the rock resistivity and nuclear magnetic resonance (NMR) experiment results, the porosity and T2 logarithmic mean values are selected as influencing factors to calculate the key parameters of the dual porosity model. Results and Discussion: The saturation of tight sandstone reservoirs in the Jurassic Ahe Formation of the Tarim Basin is calculated through the method proposed in this paper. The case study shows that the accuracy of the proposed method is higher than that of the Archie model. The method proposed in this paper demonstrates excellent adaptability in the quantitative evaluation of saturation for tight sandstone reservoirs. [ABSTRACT FROM AUTHOR]

As research in oil and gas exploration progresses, unconventional resources, such as shale gas, are increasingly becoming the focal point in the global pursuit of oil and gas resource. Shale gas reservoirs significantly differ from conventional sandstone reservoirs in aspects such as rock composition, pore type, occurrence mode, fluid, etc., thereby amplifying the challenges associated with geophysical modeling and the prediction of sweet spots. Since the formation and storage of shale gas are positively correlated with shale fracturing, a modeling approach based on Chapman theory is introduced to complete frequency-dependent petrophysical modeling. Additionally, the Frequency-dependent Amplitude Variation with Offset (FAVO) technique can estimate velocity dispersion by using the reflection coefficient information related to incidence angle and frequency. This method can more effectively identify fluids within shale reservoir. However, current FAVO forward modeling only considers the velocity dispersion and attenuation at the interface, neglecting the attenuation dispersion effects during interlayer propagation. To this end, we utilize Chapman-based petrophysical modeling as a foundation and conduct seismic forward modeling studies employing the compound matrix method. Through experimental analysis, we meticulously examine the attenuation dispersion effects at interfaces and within layers. Finally, we conduct FAVO simulations that vividly delineate the interplay between reservoir parameters and seismic responses. [ABSTRACT FROM AUTHOR]

This study demonstrates an integrated approach using a seismic-coloured inversion to derive the hydrocarbon potential of a field in the Upper Assam basin. The well-log analysis indicated the presence of hydrocarbon in the form of gas, oil, and water in sandstones with thin streaks of limestone and shale layers. The Acoustic Impedance (AI) model was generated from post-stack seismic data using a coloured inversion. Shale volume (Vshale), density, porosity and water saturation are the petrophysical parameters spatially populated using a multilayered feed-forward neural network on the inversion-based AI model. The estimated range of model-derived parameters varies as Velocity: 2136–5034 m/s, Vshale: 0–48%, Density: 2.14–2.72 gm/cc, Porosity: 6–29%, Water saturation: 9–28%, and demonstrates a reasonable correlation to well-log data. Seismic attribute for thin-fault likelihood was used to interpret the major faults. From the combined analysis based on interpreted faults and modelled parameters, the northwestern part of the study area displays a thick hydrocarbon-bearing zone (due to increasing thickness and reservoir quality). This interpretation is based on the consideration that faults are open. Thus, assuming continuity in the sequence, this northwestern region can be considered as one of the promising candidates for further exploration. [ABSTRACT FROM AUTHOR]

The North Sea Basin is the most important oil and gas producing area in Europe and the birthplace of many classic petroleum geological theories. From the perspective of multi-spheric interactions in the Earth, this study investigated the rift-foreland-rift evolution process of the North Sea Basin, which was controlled by the deep dynamic driving forces of the continental collision orogeny, mantle plume uplift, and intraplate deformation. The North Sea Basin was found to have drifted northward since the Carboniferous and passed through the low-latitude Hadley and the mid-latitude Ferrel cells. Two sets of main hydrocarbon source rocks have formed, the coals and coal measures of the Upper Carboniferous Westphalian and the marine shale of the Upper Jurassic Kimmeridge Clay Formation. We propose that the deep processes, tectonic activity, and transgression-climate evolution jointly controlled the types and horizons of the source rocks, reservoirs, and seals in different regions of the North Sea Basin. In the southern North Sea Basin, a Carboniferous-Lower Triassic gas-rich petroleum system was formed, which is characterized by transitional coal measure source rocks, desert aeolian sandstone reservoirs, and evaporite cap rocks. In the northern North Sea Basin, an Upper Triassic-Paleogene oil-rich petroleum system was formed, which is characterized by marine graben-type source rocks, deltaic sandstone and marine limestone reservoirs, and marine tight marl and shale cap rocks. The late tectonic burial and uplift in the North Sea Basin further controlled the processes of oil and gas generation and accumulation, ultimately leading to a differential distribution pattern which is oil rich in the northern part and gas rich in the southern part of the basin. In the future, there is an urgent need to re-examine the mechanisms for the petroleum generation and accumulation in large mature exploration areas (e.g., super basins such as the North Sea) and low exploration areas (e.g., the Okhotsk Sea and Arctic regions) from the perspective of multi-spheric interactions in the Earth in order to provide new theoretical support for increasing the identification of oil and gas reserves globally. The development of artificial intelligence in the petroleum industry should focus on the massive amount of exploration and geological data collected in the North Sea Basin. Through digital geological innovation, carbon neutral comprehensive utilization of oil, gas, and associated resources (e.g., helium and hydrogen) can be achieved, providing a new paradigm for global oil and gas exploration and development. [ABSTRACT FROM AUTHOR]

The Kumkol basin is located in the northern Tibetan Plateau and is a closed plateau basin with an average altitude of >4000 m and an area of nearly 20000 km2. Its boundaries are limited by the Altyn Tagh fault, East Kunlun orogen and Qimantag orogen. Studying the deep structure of the Kumkol basin reveals 2 significant implications: (1) the basin has developed a large thickness of >7000 m Cenozoic continental sediments, recording the uplift history of the northern Tibetan Plateau, and (2) preliminary work indicates that the basin is likely to have oil and gas prospects. However, owing to the adverse natural conditions of the area and the strong tectonic activity in the Cenozoic, the latter of which was not conducive to hydrocarbon preservation, only regional geological mapping and petroleum exploration route surveys have been carried out, and there is no consensus on strata, structure and tectonic evolution. From 2021 to 2022, a deep seismic reflection profile implemented by the Second Tibetan Plateau Scientific Expedition and Research (STEP) project was the first high-resolution geophysical survey across the Kumkol basin. This study uses seismic reflection migration profiles, first-arrival wave tomographic imaging and previous research results to analyze the deep structure of the basin. The final merged model contains many features of tectonic and resource significance: (1) The Kumkol basin is ∼90 km wide from north to south, with a basement depth of >9000 m. The main component is the Cenozoic continental deposits, which are divided into two major parts: the southern composite basin and the northern faulted basin. Owing to the later compression, the southern composite basin experienced significant deformation, but most parts still preserved their original sedimentary formations. (2) The structural deformation characteristics of the basin reveal a two-stage tectonic evolution process of the northern Tibetan Plateau in the Cenozoic: from the Oligocene to the Pliocene, the main mechanism was vertical differential uplift and subsidence, and after the Pliocene, it transformed to north-south compression and shortened deformation. (3) The strata, formation time, and source-reservoir-cap conditions of the Kumkol basin are similar to those of the Qaidam basin. If a breakthrough can be achieved, it is expected to expand the production capacity of the oil field in the Qaidam basin with a low-cost investment. Thus, further exploration is recommended. [ABSTRACT FROM AUTHOR]

Exploration practice has proved that deep and ultra-deep reservoirs consist of mainly matrix-porous dolomite reservoirs and fractured-vuggy karst reservoirs and still will be very important targets for future exploration, in which large oil and gas fields such as Anyue, Yuanba, Halahatang, Fuman and Shunbei have been discovered. This paper systematically summarizes three theoretical and technical achievements in studying deep and ultra-deep carbonate reservoirs in the past decade. (1) The micro-zone and multi-parameter experiment analysis technology featured by determining the "age, temperature, pressure and fluid properties" of carbonate reservoirs, together with experimental simulation of cross-tectonic-period pore formation and preservation featured by the "multi-stage, continuous, visualized and online detection technology", providing useful tools for studying the pore formation and preservation mechanism of deep and ultra-deep carbonate rocks from the perspective of "forward" and "inversion". (2) Deep and ultra-deep matrix-porous dolostone reservoirs are still controlled by sedimentary facies, among which reef (mound) and/or beach contribute most. The reservoir space is mainly composed of sedimentary primary pores and supergene dissolution pores and fractures, though some of reservoir spaces are formed by burial dissolution and they tend to develop and may locally concentrate following the pre-existing porous zone. In other words, burial dissolution vugs are inherited rather than newly formed. Early dolomite precipitation (or dolomitization) has a high potential to preserve early pores. (3) The development and preservation mechanism of fractured-vuggy karst limestone reservoirs in deep and ultra-deep realm was analyzed. Pene-contemporaneous dissolution and interlayer and buried-hill karstification control the development of early and late supergene fractured-vuggy reservoirs. Strike-slip faults superimposed with supergene karstification lead to the development of "fence-style" faulted karst reservoirs. Dissolution simulation experiments reveal that the development of karst fracturedvuggy reservoirs is facies-controlled in certain degree, mainly developed in packstone. Rock mechanics analysis reveals that the preservation of caves is under the control of lithology, cave size, and the distance to the unconformity, and caves can be well preserved at 10,000 m. The theoretical and technical achievements provide supports for carbonate oil and gas exploration into ten thousand meters deep. [ABSTRACT FROM AUTHOR]

Across various global regions abundant in oil and natural gas reserves, the presence of substantial sub‐surface salt deposits holds significant relevance. Accurate identification of salt domes becomes crucial for enterprises engaged in oil and gas exploration. Our research introduces a precise method for the automatic detection of salt domes, leveraging advanced deep learning architectures such as U‐net, transformers, artificial intelligence generative models and liquid state machines. In comparison with state‐of‐the‐art techniques, our model demonstrates superior performance, achieving a stable and validated 96%$96\%$ intersection over the union metric, indicating high accuracy and robustness. Furthermore, the Dice similarity coefficient attaining 90%$90\%$ underscores the model's proficiency in closely aligning with ground truth across diverse scenarios. This evaluation, conducted on 1000 seismic images, reveals that our proposed architecture is not only comparable but often surpasses existing segmentation models in effectiveness and reliability. [ABSTRACT FROM AUTHOR]

Modern satellite positioning and navigation technologies are not applicable in specific areas such as the exploration of oil and gas deposits by means of directional drilling techniques. Here, we can rely solely on natural geophysical fields, such as the Earth's magnetic field. The precise underground navigation of borehole drilling instruments requires a seamless, near-real-time access to operational geomagnetic data. This paper describes the MAGNUS BD hardware-software system, deployed at the Geophysical Center of the Russian Academy of Sciences, that provides the efficient accumulation, storage, and processing of geomagnetic data. This system, based on the Big Data (BD) technology, is a modern successor of the MAGNUS processing software complex developed in 2016. MAGNUS BD represents one of the first cases of the BD technology's application to geomagnetic data. Its implementation provided a significant increase in the speed of information processing and allowed for the use of high-frequency geomagnetic satellite data and expanding the overall functionality of the system. During the MAGNUS BD system's deployment on a physically separate dedicated cluster, the existing classical database (DB) was migrated to the Arenadata database with full preservation of its functionality. This paper gives a brief analysis of the current problems of directional drilling geomagnetic support and outlines the possible solutions using the MAGNUS BD system. [ABSTRACT FROM AUTHOR]

Hydraulic impactors are crucial for oil and gas exploration, but seal failure is a common issue, having an effective technique for diagnosing sealing faults can provide dependable operational and maintenance assistance for hydraulic impactors. However, identifying wear failures is challenging and there is limited data available, there has been significant interest in intelligent defect diagnosis technology that is based on deep learning in recent years. Therefore, we propose a method to enhance the data and identify faults through deep learning. Initially, the computer fluid dynamics method was used to simulate seal leakage and determine whether factors such as pressure can indicate varying levels of leaking in the seal, this approach provides a theoretical foundation for signal gathering experiments. Next, the empirical mode decomposition approach is used to separate the non-smooth pressure signal from the seal experiment, revealing fault features that indicate the extent of leakage. Finally, the improved generative adversarial network method is suggested to balance imbalanced samples by utilizing the sample overlap rate, it is paired with the auto-encoder algorithm to categorize different levels of leakage. Furthermore, a comparative analysis is conducted between the proposed methodology and several classical fault diagnosis methods. This work investigates seal damage through the lens of computational fluid dynamics and the fault identification of uneven seal samples is accomplished. [ABSTRACT FROM AUTHOR]

Purpose: This paper aims to examine the short-term market impact of the beginning of the military conflict between Russia and Ukraine (24 February 2022), the world's largest oil and gas companies. Design/methodology/approach: The authors examine the world's 100 largest listed oil and gas companies at and around the beginning of the military conflict between Russia and Ukraine using an event study methodology. Findings: The authors observe a positive and statistically significant stock price reaction at and around the military conflict. These results are consistent with the asset pricing perspective. Conversely, the stock market returns of Russian oil and gas companies, as well as those companies that were "forced" to divest in Russia due to corporate activism, exhibit a negative and statistically significant impact from the conflict. These reactions are reinforced or mitigated by company-specific characteristics such as size, profitability and institutional ownership. Finally, the findings indicate that companies engaged in oil and gas exploration and production report abnormally higher returns compared to firms in the other two subsectors of the industry. Originality/value: The effect of the war on stock markets has been relatively little examined in the financial theory. This study intends to fill this gap in the literature. [ABSTRACT FROM AUTHOR]

During the oilfield development process, various factors can cause different types of reservoir damage, leading to reduced oil well production or even shutdown, and decreased water injection capacity in water wells, resulting in significant economic losses for the oilfield. However, formation damage control measures must be based on the quantitative diagnosis of the types and degrees of reservoir damage. This paper establishes a spatiotemporal evolution numerical model for 12 common types of damage during the oil and gas exploration and development process, based on the material balance theory and Fick's diffusion law in reservoir damage processes. This model achieves numerical simulation of the degree of various reservoir damage types in different spatiotemporal domains. The overall damage degree of a specific well's evolution with time and space is further simulated in simple superposition way. The sequential core flow experiment was carried out in the laboratory, and then compared with the calculation results. The accuracy is above 90%. Finally, using field test data, the simulation results show a 95% or higher degree of agreement with the actual field measurements, proving that the reservoir damage spatiotemporal evolution quantitative simulation technology established in this paper has high accuracy and practicality. [ABSTRACT FROM AUTHOR]

Significant progress has recently been made in deep and ultra-deep oil and gas exploration globally, demonstrating enormous exploration potential of the deep and ultra-deep strata. However, the accumulation and preservation pattern of deep and ultra-deep oil and gas remains poorly understood, greatly impeding further petroleum exploration and development in the deep and ultra-deep strata. By taking the Bozi deep and ultra-deep condensate gas reservoirs in the Kuqa Depression, western China as an example, we attempt to reconstruct the hydrocarbon charge history in such deep reservoirs via an integrated investigation involving quantitative grain fluorescence, fluid inclusion petrography and microthermometry, micro-fluorescence spectroscopy, laser Raman spectroscopy, PVTx modelling, and basin modelling. The results show that: (1) The Bozi deep and ultra-deep reservoirs contain one group of gas inclusion assemblage, and two groups of oil inclusion assemblages, with one being characterized by near yellowish-whitish and blue-whitish diphasic or triphasic oil inclusions, and the other being featured by bright blue diphasic oil inclusions; (2) The first oil charge occurred during the Early Neogene (6.5-5.5 Ma), and the second oil charge occurred during the Late Neogene (4.4-3.5 Ma), under normal hydrostatic pressure or slightly weak overpressure; and (3) The gas charge occurred during the Pleistocene (∼1.6 Ma), with a corresponding reservoir pressure coefficient of approximately 1.7, transforming the reservoir fluid phase state from black oil or volatile oil to condensate gas. Our findings highlight that aside from the present burial depth, a favorable burial history model is crucial for the preservation of liquid hydrocarbons in deep and ultra-deep reservoirs. The occurrence of liquid hydrocarbons in the Bozi deep and ultra-deep condensate gas reservoirs with depths over 7,000 m is benefited from a prolonged period (>100 Ma) of shallow burial and a late-stage (since 10 Ma) rapid subsidence. [ABSTRACT FROM AUTHOR]

The Banqiao area in the Bohai Bay Basin has experienced three stages of extensional deformation, leading to the formation of numerous fault-bound traps. Faults, acting as boundary conditions for these traps, play a crucial role in hydrocarbon accumulation. In this study, we conducted a 3D structural modeling of the area using high-resolution 3D seismic data and established a fault-reservoir database based on previous research. Our findings reveal four levels of faults in the Banqiao area: basin-controlling faults, boundary faults, derivative master faults, and secondary adjusting faults. The structural units can be categorized into subsag areas, slope areas, stress tran-sition zones, bifurcation and main incised fault zones, and southern block areas. The segmented growth of the main boundary faults controls the evolution of the subsags, with the subsidence center gradually shifting eastward from Rift Phase I to Rift Phase II, aligning with the distribution of source rocks. Fault-bound traps in the Banqiao area include single faults, intersecting faults, and side faults. Faults primarily act as barriers to lateral hydrocarbon migration during the process of hydrocarbon accumulation, while also providing pathways to a lesser extent. By integrating the fault-reservoir database with the fault system classification, we identified four types of fault-controlled hydro-carbon accumulation models: like-dipping fault barrier model, oppositely-dipping fault barrier model, intersecting fault barrier model, and reactivation-controlled secondary hydrocarbon ac-cumulation model. This structural geological model effectively demonstrates the spatial configura-tion of faults and their role in hydrocarbon accumulation in the Banqiao area. The fault control mechanisms presented in the model can also be applied to other blocks in the Bohai Bay Basin, laying a foundation for future petroleum exploration in continental rifted basins and facilitating the ap-plication of big data algorithms in various geoscientific research fields. [ABSTRACT FROM AUTHOR]

Microbialite reservoirs are of great importance in oil and gas exploration. However, there is still a lack of comprehensive studies on the formation mechanisms of thrombolitic reservoirs, a specific type of microbialite. This research focuses on the oldest thrombolitic dolomite reservoir located within the Precambrian Dengying Formation in the central Sichuan Basin, southwestern China. A multi-disciplinary approach was employed to characterize different thrombolite facies and elucidate the formation mechanism of thrombolitic dolomite reservoirs and their controlling factors, involving core observation, thin-section analysis, cathodoluminescence, scanning electron microscope (SEM) microscopy, elemental analysis using LA-ICP-MS, and carbon and oxygen stable isotope analysis. Based on variations in texture, four types of thrombolite were identified: 1) distinct clotted thrombolite, 2) diffuse and regular clotted thrombolite, 3) diffuse and irregular clotted thrombolite, and 4) composite clotted thrombolite. Notably, the diffuse clotted thrombolitic dolomite is the prevalent lithology in the reservoir. Through modification by meteoric water, organic acid fluids, and hydrothermal fluids, a reservoir with dominant porosity in the form of primary growth-framework pores, dissolution pores, and vugs was formed. This resulted in the development of two high-quality reservoir intervals within the Second Member and at the top of the Fourth Member of the Dengying Formation. The growth-framework porosity of the thrombolites, epigenetic karstification, and tectonic fracturing were mainly conducive to reservoir development. However, various types of cementation have reduced porosity and connectivity within the reservoir. Overall, this study is a valuable example of the methodology required to understand meso- and microstructures of deep-buried thrombotic dolomite reservoirs, including their heterogeneities and diagenesis, as the original structures influence diagenesis. [ABSTRACT FROM AUTHOR]

Konjac glucomannan (KGM) and partially hydrolyzed polyacrylamide (HPAM) have good application prospects in the field of petroleum fracturing field, but few studies on the rheological properties of KGM and HPAM double polymer gel systems have been reported. Optimal conditions for the high temperature and shear resistant organozirconium crosslinked double polymer gel system for petroleum fracturing were explored through optimization experiments. The thickener contained a mass ratio of 2:1 of KGM to HPAM, while the organic zirconium crosslinking agent had controlled molar ratios of 1:4:3:3 of zirconium butoxide to ligand acetylacetone, triethanolamine, and glycerol. This work presents a systematic analysis of the chemical structure, microstructure, delayed crosslinking performance, temperature resistance, and shear resistance of the gel system. The study found that the crosslinking ratio of 100:2 resulted in a controllable delayed crosslinking time of the gel formed by the organic zirconium crosslinking agent and 4.0 g/L KGM/HPAM thickener within 5–25 min at room temperature. The viscosity remained above 81 mPa·s even after shearing for 100 min at 140°C and 170 s−1. These findings provide a useful reference for the application of organic zirconium crosslinked KGM/HPAM gel system in the petroleum fracturing field. [ABSTRACT FROM AUTHOR]

Well logging fluid prediction is one of the key steps in assessing oil and gas reserves. By analyzing downhole logging data, different types of fluids contained in underground rocks, such as crude oil, natural gas, and water, can be determined. This information is crucial for assessing the abundance and recoverable reserves of oil and gas resources and helps guide oil and gas exploration and development work. We have introduced a novel model called CWT (Continuous Wavelet Transform)-ViT (Vision Transformer). CWT can simultaneously provide frequency information at different scales, enabling the model to analyze downhole logging data more comprehensively and accurately at different scales. Underground rock structures often exhibit features at multiple scales, and CWT can effectively capture these features, aiding in better differentiation of different types of fluids. The ViT model utilizes the Transformer architecture, allowing for global attention over input sequences without being limited by sequence length. This enables the model to comprehensively understand the overall information of downhole logging data and extract richer features. For complex geological structures and fluid distributions in geological exploration, the global attention mechanism helps the model better grasp the overall situation, thereby improving the accuracy of fluid prediction. When we used the CWT-ViT method for well logging fluid prediction, we achieved a high accuracy rate of 97.50% in the first dataset, which further improved to 97.77% in the second dataset. These results demonstrate the significant robustness and efficiency of the CWT-ViT method in lithology prediction using well logging data. We also conducted blind well experiments, and our CWT-ViT model outperformed other models, achieving a blind well prediction accuracy of 97.36%. Therefore, the experiments indicate that the key to improving accuracy in well logging fluid prediction with CWT lies in its multiscale analysis capability, effectively capturing different fluid characteristic frequencies. Additionally, CWT enhances signal features and removes noise, increasing the precision of fluid identification. Finally, the integration with ViT further optimizes fluid prediction performance, making it outstanding in complex geological environments. The advantages of ViT in fluid prediction include its excellent sequence modeling capability, effective handling of long-distance dependencies, and enhanced ability to capture fluid characteristics in complex well logging data. [ABSTRACT FROM AUTHOR]

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, the principal component model combined with the singularity index model, and the cluster analysis combined with the principal component model and the singularity index model. 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. [ABSTRACT FROM AUTHOR]

Faults, as a kind of fracture tectonics, play a role in reservoir closure or provide oil and gas transportation channels. The accurate understanding of the distribution characteristics of faults is significant for oil and gas exploration. The traditional fractal dimension for fault number (Df3) cannot comprehensively characterize the complexity and heterogeneity of fault network distribution. In this paper, a fractal characterization method on three-dimensional (3D) tortuosity of fault tectonics is proposed based on 3D seismic exploration. The methodology is described in detail to establish the model on the fractal dimension for the 3D tortuosity of fault tectonics. The results show the proposed method of estimation of the DT3 displaying high accuracy and rationality. Compared with the traditional fractal dimension Df3, the proposed DT3 can comprehensively characterize the fractal characteristics of faults network systems in the 3D space. This study achieves a breakthrough in the fractal characterization of the 3D tortuosity of fault tectonics. It is worth further study for establishing an analytical fractal equation based on the DT3 and oil or gas transfer, which can provide the theoretical foundation and technical support for oil and gas exploration. [ABSTRACT FROM AUTHOR]

Cambrian shales in China and elsewhere contain abundant oil and gas resources. However, due to its deep burial and limited outcrop, there has been relatively little research conducted on it. The Cambrian shale of the Tadong low uplift in the Tarim Basin of western China, specifically the Xidashan–Xishanbulake Formation (Fm.) and overlying Moheershan Fm. provide a case study through the use of organic petrology, mineralogy, organic and elemental geochemistry, with the aim of analyzing and exploring the hydrocarbon generation potential (PG) and organic matter (OM) enrichment mechanisms within these shale formations. The results indicate that: (1) the Cambrian shale of the Tadong low uplift exhibits relatively dispersed OM that consists of vitrinite‐like macerals and solid bitumen. These formations have a higher content of quartz and are primarily composed of silica‐based lithology; (2) shale samples from the Xidashan–Xishanbulake and Moheershan formations demonstrate high total organic carbon (TOC) and low pyrolytic hydrocarbon content (S2) content. The OM is predominantly type I and type II kerogens, indicating a high level of maturation in the wet gas period. These shales have undergone extensive hydrocarbon generation, showing characteristics of relatively poor PG; (3) the sedimentary environments of the Xidashan–Xishanbulake and Moheershan formations in the Tadong low uplift are similar. They were deposited in warm and humid climatic conditions, in oxygen‐deficient environments, with stable terrigenous inputs, high paleoproductivity, high paleosalinity, weak water‐holding capacity, and no significant hydrothermal activity; and (4) the relationship between TOC and the paleoproductivity parameter (P/Ti) is most significant in the Lower Cambrian Xidashan–Xishanbulake Fm., whereas correlation with other indicators is not evident. This suggests a productivity‐driven OM enrichment model, where input of land‐derived material was relatively small during the Middle Cambrian, and the ancient water exhibited lower salinity. A comprehensive pattern was formed under the combined control of paleoproductivity and preservation conditions. This study provides valuable guidance for oil and gas exploration in the Tarim Basin. [ABSTRACT FROM AUTHOR]

Accurate well log data is critical for subsurface characterisation and decision-making in the petroleum exploration. We explore and compare the effectiveness of three distinct deep leaning (DL) approaches—Long Short-Term Memory, Bidirectional Long Short-Term Memory, and Convolutional Long Short-Term Memory networks—in predicting missing well log data, a common challenge in the data acquired by Energy and Production (E&P) companies. Our analysis revealed the complex, nonlinear relationships present in geophysical logs through correlation matrix and determining the rank of predictor features through Minimum Redundancy Maximum Relevance (MRMR) analysis. To weigh these models, we used real-field wireline log datasets from the Bhogpara oil field of Upper Assam basin. The performance of each model is evaluated through root mean square error, correlation coefficients, mean absolute error and variance between actual and predicted values. The uncertainty of the models was facilitated by Monte Carlo simulation. Deep learning models accurately predicted neutron porosity logs from gamma-ray, resistivity, density, and photoelectric factor logs. The high correlation coefficients during the training (exceeding 0.90) and test (exceeding 0.97) phases illustrated the predictive precision of the DL models. Conv-LSTM consistently outperforms LSTM and Bi-LSTM, indicating the integration of convolutional layers in feature extraction offers a significant advantage in capturing intricate patterns in log data. The research showcases the effectiveness of deep learning architectures in predicting missing logs, a crucial aspect for E&P companies, as log data is vital for decision-making. The study presents a novel method for preserving data integrity and facilitating informed decision-making. [ABSTRACT FROM AUTHOR]

The presence of abundant clay components and microporous structure in shale results in its high hydrophilicity, making a water-rich environment inevitable in petroleum exploration projects. Therefore, it is crucial to consider the influence of bedding structure, moisture content, confining pressure, and their combined effects on the geomechanical properties of shale. This article aims to investigate the mechanical properties of deep shale under varying water content conditions, elucidate the failure mode and failure mechanism of shale in actual engineering scenarios, and explores the interplay between stress, structure, moisture content, and other factors on its mechanical properties. The evaluation of wellbore stability and fracture propagation effects is proposed based on laboratory experiments using triaxial stress and strain data, along with the application of energy evolution theory. The experimental procedures encompass an analysis of shale's microscopic components and structure, as well as anisotropic shale triaxial compression tests conducted under different moisture contents and confining pressures. The results demonstrate that shale exhibits dense pores in its microstructure and displays pronounced anisotropic characteristics in its macrostructure. The presence of water within these pores, combined with the in situ stress within the formation, significantly influences the mechanical properties of shale. This anisotropy decreases with increasing moisture content, but the mechanical performance still decreases. Under triaxial compression conditions, the increase in confining pressure to some extent enhances the anisotropy of shale's deformation characteristics, which is related to the failure modes of shale. However, the detrimental effect of moisture content on shale's mechanical properties still persists. In order to quantify the impact of these factors, this study utilizes the elastic modulus as an indicator of the coupling effect. It combines the triaxial strain curve obtained from laboratory tests and proposes an evaluation index for shale mechanical properties based on the energy evolution theory. This index is suitable for assessing wellbore stability (the stability index called SIr) and crack expansion (the brittleness index called BIr). The calculation results reveal that, during the wellbore drilling process, excavating parallel to the direction of shale bedding while maintaining low moisture content and high confining pressure yields a higher SIr value, indicating better wellbore stability. On the other hand, during reservoir fracturing, fracturing perpendicular to the shale bedding direction and maintaining low confining pressure and moisture content result in a smaller BIr value. This approach is more beneficial for the expansion of shale fracture network in engineering. [ABSTRACT FROM AUTHOR]

Shallow resources are becoming increasingly depleted, deep resource exploration has become a global strategy. The design and testing of deep in-situ core samples are prerequisites for exploring deep resources; however, no in-situ condition-preserved coring and testing techniques and tools have been reported yet. Here, the first deep in-situ conditionpreserved coring system (with the preservation of pressure, temperature, substance, light, and moisture) was developed that considers the effects of high water pressure and formation dynamic loads, along with an in-situ condition-preserved testing system. A pressurepreserved controller was designed, achieving the ultimate capacity of 140 MPa and 150 ℃. A temperature-preserved coring system combining active heating and passive insulation was constructed, realizing temperature preservation from room temperature to 150 ℃. Three generations of film-formation principles and methods were designed, achieving an excellent quality preserved rate, moisture preserved rate, and visible light barrier rate. Moreover, a deep in-situ condition-preserved coring system, and a simulated coring platform for large cores under in-situ environments was fabricated. A non-contact testing system was derived to cut and prepare specimens under in-situ environment and to perform non-contact non-destructive testing and true triaxial testing. The research findings can be successfully applied to deep coal and gas development, deep oil and gas resources assessment, and deep-sea sediment prospecting, achieving excellent application outcomes. This study provides important theoretical, technical and hardware support for deep in-situ rock physics and mechanics research and deep resource exploitation. [ABSTRACT FROM AUTHOR]

This study aims to expand on existing connections between magnetic minerals and hydrocarbons within petroleum systems. Previous studies have focussed on single-source petroleum systems whereas this study, for the first time, analyses a multi-source petroleum system to investigate potential correlations between different kerogen type source rocks and magnetic minerals. To do this, the study investigates the magnetic mineral characteristics of the Inner Moray Firth (IMF), UK North Sea, through room-, low- and high-temperature techniques, and correlates this to published basin and petroleum systems modelling results that show a three-source hydrocarbon mix. Magnetic mineral analysis identifies extensive evidence for magnetite, goethite and siderite, alongside more minor lepidocrocite and iron sulphides. Although we find that magnetite is ubiquitous within the IMF, its abundance is relatively low, and, in contrast, the relatively magnetically weak goethite is more likely the most abundant magnetic mineral throughout the IMF. In agreement with previous studies, we find magnetic enhancement at oil-water contacts (OWCs); however, here, we identify two different magnetic enhancement processes at OWCs in wells, which are dependent on the amount of sulphur available in the local environment. Wells with low levels of sulphur have increasing levels of magnetite towards the OWC, with the magnetic enhancement occurring at the top of the water-saturated section. Sulphur-rich environments display an increase in iron sulphides near the OWC at the bottom of the oil-saturated sediments. Additionally, we confirm the presence of siderite as indicator of upward vertical migration. Combining with petroleum system model predictions, we find direct links between iron hydroxide presence and Type I and II–III kerogen source rocks, and iron sulphide presence with Type II kerogen source rocks. This study shows the potential for further utilization of magnetic mineral analysis within hydrocarbon exploration and petroleum system definition. [ABSTRACT FROM AUTHOR]

A large language model (LLM) is constructed to address the sophisticated demands of data retrieval and analysis, detailed well profiling, computation of key technical indicators, and the solutions to complex problems in reservoir performance analysis (RPA). The LLM is constructed for RPA scenarios with incremental pre-training, fine-tuning, and functional subsystems coupling. Functional subsystem and efficient coupling methods are proposed based on named entity recognition (NER), tool invocation, and Text-to-SQL construction, all aimed at resolving pivotal challenges in developing the specific application of LLMs for RDA. This study conducted a detailed accuracy test on feature extraction models, tool classification models, data retrieval models and analysis recommendation models. The results indicate that these models have demonstrated good performance in various key aspects of reservoir dynamic analysis. The research takes some injection and production well groups in the PK3 Block of the Daqing Oilfield as an example for testing. Testing results show that our model has significant potential and practical value in assisting reservoir engineers with RDA. The research results provide a powerful support to the application of LLM in reservoir performance analysis. [ABSTRACT FROM AUTHOR]

Using gas and rock samples from major petroliferous basins in the world, the helium content, composition, isotopic compositions and the U and Th contents in rocks are analyzed to clarify the helium enrichment mechanism and distribution pattern and the exploration ideas for helium-rich gas reservoirs. It is believed that the formation of helium-rich gas reservoirs depends on the amount of helium supplied to the reservoir and the degree of helium dilution by natural gas, and that the reservoir-forming process can be summarized as "multi-source helium supply, main-source helium enrichment, helium-nitrogen coupling, and homogeneous symbiosis". Helium mainly comes from the radioactive decay of U and Th in rocks. All rocks contain trace amounts of U and Th, so they are effective helium sources. Especially, large-scale ancient basement dominated by granite or metamorphic rocks is the main helium source. The helium generated by the decay of U and Th in the ancient basement in a long geologic history, together with the nitrogen generated by the cracking of the inorganic nitrogenous compounds in the basement rocks, is dissolved in the water and preserved. With the tectonic uplift, the ground water is transported upward along the fracture to the gas reservoirs, with helium and nitrogen released. Thus, the reservoirs are enriched with both helium and nitrogen, which present a clear concomitant and coupling relationship. In tensional basins in eastern China, where tectonic activities are strong, a certain proportion of mantle-derived helium is mixed in the natural gas. The helium-rich gas reservoirs are mostly located in normal or low-pressure zones above ancient basement with fracture communication, which later experience substantial tectonic uplift and present relatively weak seal, low intensity of natural gas charging, and active groundwater. Helium exploration should focus on gas reservoirs with fractures connecting ancient basement, large tectonic uplift, relatively weak sealing capacity, insufficient natural gas charging intensity, and rich ancient formation water, depending on the characteristics of helium enrichment, beyond the traditional idea of searching for natural gas sweetspots and high-yield giant gas fields simultaneously. [ABSTRACT FROM AUTHOR]

The Bohai Bay Basin, as a super oil-rich basin in the world, is characterized by cyclic evolution and complex regional tectonic stress field, and its lifecycle tectonic evolution controls the formation of regional source rocks. The main pre-Cenozoic stratigraphic system and lithological distribution are determined through geological mapping, and the dynamics of the pre-Cenozoic geotectonic evolution of the Bohai Bay Basin are investigated systematically using the newly acquired high-quality seismic data and the latest exploration results in the study area. The North China Craton where the Bohai Bay Basin is located in rests at the intersection of three tectonic domains: the Paleo-Asian Ocean, the Tethys Ocean, and the Pacific Ocean. It has experienced the alternation and superposition of tectonic cycles of different periods, directions and natures, and experienced five stages of the tectonic evolution and sedimentary building, i.e. Middle-Late Proterozoic continental rift trough, Early Paleozoic marginal-craton depression carbonate building, Late Paleozoic marine-continental transitional intracraton depression, Mesozoic intracontinental strike-slip-extensional tectonics, and Cenozoic intracontinental rifting. The cyclic evolution of the basin, especially the multi-stage compression, strike-slip and extensional tectonics processes in the Hercynian, Indosinian, Yanshan and Himalayan since the Late Paleozoic, controlled the development, reconstruction and preservation of several sets of high-quality source rocks, represented by the Late Paleozoic Carboniferous-Permian coal-measure source rocks and the Paleogene world-class extra-high-quality lacustrine source rocks, which provided an important guarantee for the hydrocarbon accumulation in the super oil-rich basin. [ABSTRACT FROM AUTHOR]

Based on the oil and gas exploration in western depression of the Qaidam Basin, NW China, combined with the geochemical, seismic, logging and drilling data, the basic geological conditions, oil and gas distribution characteristics, reservoir-forming dynamics, and hydrocarbon accumulation model of the Paleogene whole petroleum system (WPS) in the western depression of the Qaidam Basin are systematically studied. A globally unique ultra-thick mountain-style WPS is found in the western depression of the Qaidam Basin. Around the source rocks of the upper member of the Paleogene Lower Ganchaigou Formation, the structural reservoir, lithological reservoir, shale oil and shale gas are laterally distributed in an orderly manner and vertically overlapped from the edge to the central part of the lake basin. The Paleogene WPS in the western depression of the Qaidam Basin is believed unique in three aspects. First, the source rocks with low organic matter abundance are characterized by low carbon and rich hydrogen, showing a strong hydrocarbon generating capacity per unit mass of organic carbon. Second, the saline lake basinal deposits are ultra-thick, with mixed deposits dominating the center of the depression, and strong vertical and lateral heterogeneity of lithofacies and storage spaces. Third, the strong transformation induced by strike-slip compression during the Himalayan resulted in the heterogeneous enrichment of oil and gas in the mountain-style WPS. As a result of the coordinated evolution of source-reservoir-caprock assemblage and conducting system, the Paleogene WPS has the characteristics of "whole process" hydrocarbon generation of source rocks which are low-carbon and hydrogen-rich, "whole depression" ultra-thick reservoir sedimentation, "all direction" hydrocarbon adjustment by strike-slip compressional fault, and "whole succession" distribution of conventional and unconventional oil and gas. Due to the severe Himalayan tectonic movement, the western depression of the Qaidam Basin evolved from depression to uplift. Shale oil is widely distributed in the central lacustrine basin. In the sedimentary system deeper than 2 000 m, oil and gas are continuous in the laminated limy-dolomites within the source rocks and the alga limestones neighboring the source kitchen, with intercrystalline pores, lamina fractures in dolomites and fault-dissolution bodies serving as the effective storage space. All these findings are helpful to supplement and expand the WPS theory in the continental lake basins in China, and provide theoretical guidance and technical support for oil and gas exploration in the Qaidam Basin. [ABSTRACT FROM AUTHOR]

The exploration and development of deep oil and gas resources are becoming the primary focus in the fossil energy sector, thereby increasing the demand for highly skilled engineers. Colleges and universities play a crucial role in cultivating talent in petroleum engineering. However, the current traditional teaching systems, particularly in experimental practices, face significant challenges, such as low efficiency, limited environments, and a disconnect between theoretical knowledge and practical application. To address these issues and enhance learners' practical abilities and comprehension, we introduced digital twin technology into the experimental teaching of deep energy exploitation. This paper analyzes innovative pedagogical approaches, with a special emphasis on the real-time visualization of hydraulic fracturing. Supported by the National Key Laboratory of Chengdu University of Technology, our research team developed multiple digital twin platforms for both indoor and onsite hydraulic fracturing. These platforms utilize advanced algorithms and models, enabling real-time data acquisition and visualization analysis. Pilot teaching results demonstrate that the virtual experimental system based on digital twin technology encourages active learner engagement, improves their understanding of digitalization in engineering, and enhances their professional skills in deep oil and gas exploration. The digital twin-based visualization system is a valuable tool for experimental teaching in deep energy exploitation, and its application could serve as a model for other engineering disciplines. [ABSTRACT FROM AUTHOR]

The practice of oil and gas exploration has confirmed the existence of recoverable shale oil resources in the Permian Lucaogou Formation on the northern edge of the Bogda Mountains. However, previous research on the development characteristics and main controlling factors of shale oil resources in this area is relatively limited. In order to elucidate the development characteristics and principal controlling factors of the shale deposit in the Lucaogou Formation, the characteristics, physical properties, diagenesis, and influencing factors of the shale ore were investigated utilising data derived from outcrop, drilling, seismic, and geochemical analysis. The findings indicate that the shale of the Lucaogou Formation is prevalent and extensive. The deposit's lithology is predominantly composed of dark grey and grey-black mud shale, interspersed with thin layers of dark grey and grey-black sandy mud shale and dolomite mud shale. The most prevalent minerals are carbonate minerals, followed by feldspar and quartz, with a notable proportion of brittle minerals. The deposit is primarily composed of dissolution pores, bedding fractures, and structural fractures, with a porosity of 1.23–3.26% and permeability of 0.012–0.076 mD, which are characteristic of ultra-low porosity and ultra-low permeability deposits. Among the three deposit types, the sandstone type exhibits the most favourable physical properties, followed by the dolomite type and the shale type, which displays the least favourable properties. The shale of the Lucaogou Formation is currently in the middle diagenetic phase, which is characterised by compaction, cementation (carbonate cementation, mudstone cementation, pebble cementation), and dissolution. The destructive effect of compaction and cementation on the physical properties is counterbalanced by the constructive effect of dissolution. The diagenetic environment has gradually changed from an alkaline environment to a slightly alkaline, slightly acidic stage. [ABSTRACT FROM AUTHOR]

Optimizing fracturing parameters is crucial for enhancing production and reducing costs in oil and gas exploration and development. Effectively integrating geological and engineering parameters for the automated optimization of fracturing design continues to pose challenges. This study utilizes the cluster-based local outlier factor method for anomaly detection and removal from the dataset, significantly enhancing data quality. By integrating diverse models, including tree-based models and neural networks, an ensemble model for production prediction was developed. This approach successfully addresses the limitations of relying on a single model and achieves high-precision production forecasting. Furthermore, a Covariance Matrix Adaptation Evolution Strategy (CMA-ES)-based framework was established to comprehensively optimize the design parameters of fracturing projects. Optimization practices for two selected wells resulted in a 168.54% increase in production and identified the optimal design parameter configuration for all cases studied. The results of this study demonstrate the feasibility and effectiveness of the proposed ensemble prediction model and optimization framework in practical applications. Data-driven optimization strategies are expected to play a larger role in future oil and gas development, driving technological innovation and advancement in the field. [ABSTRACT FROM AUTHOR]

To study the oil and gas enrichment characteristics of the reservoir rocks in the second Member of the Nantun Formation (N2) of the F1 fault in the Beier Depression, this research focuses on the mechanism of shortening the sealing time of the regional mudstone cap due to faults and the factors influencing the sealing duration. The period during which the regional mudstone cap seal began is determined by analyzing the relationship between the diagenetic index of the regional mudstone cap and its underlying reservoir rocks and time. This relationship between the rock-formation index and time helps establish the onset of regional mudstone cap seal, and from this, the index of shortening time due to faults is derived. A research framework to study the sealing time shortening of regional mudstone cap seal caused by a fault was developed, which was further applied to analyze the relationship between the fault-induced shortening time of the seal in the lower of the first Member of the Damoguaihe Formation section ( D 1 x ) of the Beier Depression and hydrocarbon concentrations in the N2 Formation. The results show that the F1 fault at measurement points 1–4, 6, and 9–11 reduced the blocking time of the regional mudstone cap in  D 1 x  to 100%, hindering hydrocarbon accumulation and preservation in the N2. Conversely, the F1 fault at measurement points 5, 7, 8, and 12–15 reduces the blocking time of the regional mudstone cap in the  D 1 x  by 37–99%, which is more conducive to hydrocarbon accumulation and preservation in N2, resulting in positive oil and gas shows. Based on the test results, a discussion on the feasibility, applicability, and limitations of the new method is conducted, yielding the following conclusions: (1) The relationship between oil and gas indications in the reservoir rocks of the Nan'er Member confirms the feasibility of the new method. The research findings of the new method on the F1 fault align with current oil and gas exploration realities, indicating its potential use in studying the degree to which faults shorten the sealing time of regional mudstone caprocks. (2) The new method is primarily applicable to the study of the modification effects of tensile normal faults on regional mudstone caprocks and their impact on oil and gas sealing capacities. However, its application to other types of faults may have limitations. (3) The new method is mainly suitable for caprocks dominated by mudstone. When studying other types of caprocks, such as carbonate rocks, evaporites, igneous rocks, and metamorphic rocks, different research methods and technical means are required. These findings provide valuable insights for oil and gas exploration efforts near fault zones. [ABSTRACT FROM AUTHOR]

The Ahdeb oil field is located in the southwestern part of the Zagros fold deformation zone. The study of the model of the formation of the oil reservoir in this field will be helpful to deepen the pattern of hydrocarbon distribution in this zone. In this paper, we use the seismic data of the Ahdeb oil field to recover the tectonic evolution history of the field. Under neotectonic movement, the oil field formed in the early stage, migrated to the high point in the late stage, and finally entered the present formation. From here, for the oil-bearing inclusions within the reservoir, the photometric absorption values of the organic matter groups were measured by infrared spectroscopy. Their ratios were used to evaluate the maturity, thus discovering two phases of oil charging. Finally, using the hydrocarbon generation history and tectonic evolution history, combined with the oil and gas transportation periods in the reservoir, we deduce that the reservoir formation mode in the area is a two-phase gathering and final adjustment formation mode. This understanding of the hydrocarbon formation patterns will promote oil and gas exploration in this zone. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Basin modeling and thermal maturity estimation are crucial for understanding sedimentary basin evolution and hydrocarbon potential. Assessing thermal maturity in the oil and gas industry is vital during exploration. With artificial intelligence advancements, more accurate evaluation of hydrocarbon source rocks and efficient thermal maturity estimation are possible. This study employed 1D basin modeling using PetroMod and a novel hybrid group method of data handling (GMDH) neural network optimized by a differential evolution (DE) algorithm to estimate thermal maturity (Tmax) and assess kerogen type in Triassic–Jurassic source rocks of the Mandawa Basin, Tanzania. The GMDH–DE addresses the limitations of conventional methods by offering a data-driven approach that reduces computational time, overcomes overfitting, and improves accuracy. The 1D thermal maturity basin modeling suggests that the Mbuo source rocks reached the gas–oil window in late Triassic times and began expulsion in the early Jurassic while located in an immature-to-mature zone. The GMDH–DE model effectively estimated Tmax with high coefficient of determination (R2 = 0.9946), low root mean square error (RMSE = 0.004), and mean absolute error (MAE = 0.006) during training. When tested on unseen data, the GMDH–DE model yielded an R2 of 0.9703, RMSE of 0.017, and MAE of 0.025. Moreover, GMDH–DE reduced the computational time by 94% during training and 87% during testing. The results demonstrated the model's exceptional reliability compared to the benchmark methods such as artificial neural network–particle swarm optimization and principal component analysis coupled with artificial neural network. The GMDH–DE Tmax model offers a unique and independent approach for rapid real-time determination of Tmax values in organic matter, promoting efficient resource assessment in oil and gas exploration. [ABSTRACT FROM AUTHOR]

Widespread submarine hydrocarbon seepage can form complex fluid seepage characteristics, with submarine sediment geochemistry effectively recording seepage activities and fluid component changes due to hydrocarbon seepage. This is crucial for offshore oil and gas exploration and understanding global climate change. Therefore, using the geochemical information of submarine sediments to trace hydrocarbon seepage activities is of great significance. In order to identify the geochemical anomaly characteristics and genetic types of acid-hydrolyzed hydrocarbons in submarine sediments in the Yantai Depression of the South Yellow Sea Basin, Eastern China, and to explore the relationship between these anomalies and deep oil and gas, geochemical columnar samples were taken at 100 stations in the study area. A total of 100 sets of acid-hydrolyzed hydrocarbon data and 26 sets of carbon isotope data were analyzed. The results show that the content of acid-hydrolyzed hydrocarbons at each station is in the following order: methane (AC1) > ethane (AC2) > propane (AC3) > butane (AC4) > pentane (AC5). The determination coefficient between the saturated hydrocarbon indicators exceeds 0.9, indicating that these components have the same source. Data analysis reveals that the genetic type of hydrocarbon gases in the study area is generally thermogenic, with limited microbial contribution to saturated hydrocarbons, indicating deep oil and gas characteristics. The coincidence between the anomalous areas and geological structures indicates that the distribution of these anomalies is closely related to fault distribution. [ABSTRACT FROM AUTHOR]

The East China Sea Basin (ECSB) is an integral part of the Western Pacific tectonic system. Its development is linked to the Kula–Pacific Plate and the formation and expansion of the Philippine Sea Basin. Recent advancements in exploration technologies and theory have been applied to Mesozoic basins in the East China Sea. Researchers have posited that the southern basin has great oil and gas exploration potential. However, the characteristics and evolution of fault structures and their influence on hydrocarbon accumulation remain unclear. Here, in-depth geometric and kinematic analyses of Mesozoic fault structures in the southern ECSB were conducted using the latest interpretations of 2D seismic data and structural analysis theory. The findings revealed that the fault system was well developed and predominantly exhibited multiphase extensional and extensional-torsional features. Based on their lateral distribution and morphology, faults were categorized into three structural styles and seven combinations. According to their developmental timing, periods of active faulting were attributed to the Yanshan and Himalayan epochs. Multiphase fault activities strongly controlled the formation of traps and thus hydrocarbon accumulation, while earlier NE-trending faults controlled the formation of structural belts and hydrocarbon source areas. [ABSTRACT FROM AUTHOR]

As global energy demands continue to rise, the development of unconventional oil resources has become a critical priority. However, the complexity and high dimensionality of these problems often cause existing optimization methods to get trapped in local optima when designing key tools, such as deep-sea probes. To address this challenge, this study proposes a novel meta-heuristic approach—the Salmon Salar Optimization algorithm, which simulates the social structure and collective behavior of salmon to perform high-precision searches in high-dimensional spaces. The Salmon Salar Optimization algorithm demonstrated superior performance across two benchmark function sets and successfully solved the constrained optimization problem in deep-sea probe design. These results indicate that the proposed method is highly effective in meeting the optimization needs of complex engineering systems, particularly in the design optimization of deep-sea probes for unconventional oil exploration. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Natural Gas Geoscience is the property of Natural Gas Geoscience and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Submarine fan reservoirs are important accumulation zones for oil, gas, and natural gas hydrates, offering significant potential for hydrocarbon exploration. During the deposition period of the Sanya Formation in the southern part of the Changchang Sag of the Qiongdongnan Basin, a large submarine fan developed. However, the internal structure, source-sink system, and formation mechanism of this fan remain poorly understood, posing significant challenges to exploration in this area. This paper examines the source-to-sink sedimentary processes and deposition of submarine fans, using the Changchang Sag, in the Qiongdongnan Basin in the Northern South China Sea, as an example, which will provide valuable general guidance for deep water oil and gas exploration. Based on the theories of seismic stratigraphy and seismic sedimentology, this paper utilizes techniques such as seismic facies analysis, seismic attribute optimization, paleogeomorphology reconstruction, and source-to-sink sedimentary systemanalysis to analyze the 3D seismic data of the study area. Research indicates that the Sanya Formation in the Changchang Sag of the Qiongdongnan Basin comprises three depositional units: submarine fan, feeder channel, and Semi-deep marine to deep marine mudstone. The submarine fan is a fan formed by the coupling and convergence of submarine fans sourced from the southwest and southeast. Internally, it is divided into three sub-facies: the proximal fan of the sand-rich submarine fan, the main body of the sand-rich submarine fan lobes, and the distal lobes of the sand-rich submarine fan. The submarine fan sourced from the southwest extends nearly north-south and is primarily fed by sediment transported through three large, banded ancient valleys. The sedimentary filling is characterized by three-phase progradation. The submarine fan sourced from the southeast extends nearly east-west and is primarily fed by sediment transported through a single large, banded ancient valley. The sedimentary filling is characterized by two-phase lateral accumulation. During the deposition period of the Sanya Formation, certain areas of the southern uplift belt were exposed for extended periods and subjected to weathering and erosion. Sediments are transported to large ancient valleys through small supply channels. A large number of sediments were transported to the southern slope of the Changchang sag through the provenance channel system such as large ancient valleys and slope belts and deposited in the center of the sag. These make up a complete system of large ancient uplifts and submarine fan source-to-sink sedimentary systems. The sedimentary model is a lobed submarine fan controlled by semi-restricted ancient valleys and expansive basins. [ABSTRACT FROM AUTHOR]

The Yamal-Nenets Autonomous District, especially the Yamal Peninsula located in the permafrost zone, stores Russia's largest oil and gas resources. However, development in the area is challenging because of its harsh climate and engineering–geological features. Drilling in oil and gas fields in permafrost faces problems that are fraught with serious accident risks: soil heaving leading to the collapse of wellheads and hole walls, deformation and breakage of casing strings, gas seeps or explosive emissions, etc. In this respect, knowledge of the permafrost's structure is indispensable to ensure safe geological exploration and petroleum production in high-latitude regions. The extent and structure of permafrost in West Siberia, especially in its northern part (Yamal and Gydan Peninsulas), remain poorly studied. More insights into the permafrost's structure have been obtained by a precise sTEM survey in the northern Yamal Peninsula. The sTEM soundings were performed in a large oil and gas field where permafrost is subject to natural and anthropogenic impacts, and its degradation, with freezing–thawing fluctuations and frost deformation, poses risks to exploration and development operations, as well as to production infrastructure. The results show that permafrost in the western part of the Yamal geocryological province is continuous laterally but encloses subriver and sublake unfrozen zones (taliks) and lenses of saline liquid material (cryopegs). The total thickness of perennially frozen rocks is 200 m. The rocks below 200 m have negative temperatures but are free from pore ice. Conductive features (<10 Ohm﮲m) traceable to the permafrost base may represent faults that act as pathways for water and gas fluids and, thus, can cause a geohazard in the oil and gas fields (explosion of frost mounds, gas blow during shallow drilling, etc.). [ABSTRACT FROM AUTHOR]

The characteristics of elements, isotopes, and small shelly fossils were investigated for Late Ediacaran to Early Cambrian stratigraphy division and to discuss their geological implications in the northwestern Sichuan Basin. The results reveal that small shelly fossils can be detected in the high-phosphorous section, with the concentration of phosphorus mainly ranging from 2% to 8%, suggesting that this interval belongs to the Early Cambrian, which is also consistent with the carbon isotopic composition results. In addition, the Early Cambrian is denudated in the Sichuan Basin due to tectonic movement, and the characteristics of some isotopes and small shell fossils are different from those in other basins. It can be proposed that P content can support the recognition of lithological boundaries, and the high phosphorus content can be used as a reference to identify the top and bottom boundaries of the Maidiping Formation in the study area. According to the elemental compositions in the Ediacaran Dengying Formation, the variations in Si, Al, Fe, and K contents are similar in the platform area and rift area, suggesting that the third and fourth member of the Dengying Formation are also developed in the Deyang-Anyue Rift. The results suggest that both the Deng-4 member and Maidiping Formation feature contemporaneous deposition of different facies in the northwestern Sichuan Basin. The strata consist of shale intercalated with thin carbonate rock deposits in the Deyang-Anyue Rift, while carbonate rock deposits in the platform. The Deyang-Anyue Rift expanded gradually in the Late Ediacaran and eventually filled in the Early Cambrian. The data in this study illustrate that elemental compositions, isotopes, and small shelly fossils can be combined to correlate the Late Ediacaran to Early Cambrian strata and provide new evidence for Deyang-Anyue Rift evolution. The results offer some new insights for deep oil and gas exploration in the Sichuan Basin and for the tectonic-depositional-environmental-biological synergistic evolution in the Late Ediacaran to Early Cambrian transition. [ABSTRACT FROM AUTHOR]

In this study, the Xgboost method is employed for TOC estimation in mixed carbonate and siliciclastic shale from the Hashan area, Junggar Basin. The results show that this approach is effective for TOC estimation in this area although the model performance is not very excellent with a correlation coefficient of 0.54 between measured TOC and predicted TOC values, likely due to a small samples dataset. Therefore, the PCA method is applied to debase dimension of well log data from five dimensional to two-dimensional data, which enhances the correlation coefficient between the predicted and measured TOC from 0.54 to 0.68. Based on the model, the isopleth maps of TOC distributions in Fengcheng Formation were redrawn showing two shale oil exploration targets, which likely correspond to two depositional centers of this strata. All the same, the model in this work provides reliable data for shale oil evaluation in the study area and a good example under similar geological setting. [ABSTRACT FROM AUTHOR]

Crude oil contamination has been widely recognized as a major environmental issue due to its various adverse effects. The use of inhabitant microorganisms (native to the contaminated sites) to detoxify/remove pollutants owing to their diverse metabolic capabilities is an evolving method for the removal/degradation of petroleum industry contaminants. The present study deals with the exploitation of native resident bacteria from crude oil contaminated site (oil exploration field) for bioremediation procedures. Fifteen (out of forty-four) bioremediation-relevant aerobic bacterial strains, belonging to the genera of Bacillus, Stenotrophomonas, Pseudomonas, Paenibacillus, Rhizobium, Burkholderia, and Franconibacter, isolated from crude oil containing sludge, have been selected for the present bioremediation study. Crude oil bioremediation performance of the selected bacterial consortium was assessed using microcosm-based studies. Stimulation of the microbial consortium with nitrogen or phosphorous led to the degradation of 60–70% of total petroleum hydrocarbon (TPH) in 0.25% and 0.5% crude oil experimental sets. CO2 evolution, indicative of crude oil mineralization, was evident with the highest evolution being 28.6 mg mL−1. Ecotoxicity of treated crude oil-containing media was assessed using plant seed germination assay, in which most of the 0.25% and 0.5% treated crude oil sets gave positive results thereby suggesting a reduction in crude oil toxicity. [ABSTRACT FROM AUTHOR]