To investigate the characteristics of shale gas occurrence and evolution under stratigraphic conditions of the Longmaxi Formation in the Luzhou Area, volumetric methane isothermal adsorption experiments under different hydration states were conducted. A ternary Langmuir model was employed to fit the shale excess adsorption data, yielding a maximum corrected adsorption capacity of 2.5 cm³/g. Total organic carbon content and clay minerals were identified as favorable controlling factors for methane adsorption capacity, and increasing water saturation exerts an inhibitory effect on methane adsorption. With increasing burial depth, adsorbed gas content initially increases and then decreases, and free gas content continues to rise. Under hydrated conditions, an equivalent burial depth exists where adsorbed and free gas contents intersect. This critical depth migrates upward with increasing hydration, forming a mixed gas occurrence zone. The evolutionary process of deep shale gas in the Luzhou Area can be divided into four stages. From the early deposition period to the Late Silurian, rapid subsidence of the stratum facilitated the dominance of biogenically derived adsorbed gas. During the Early Devonian to Middle Triassic, continuous subsidence of the strata persisted alongside minor uplift events, yet adsorbed gas remained the predominant occurrence mode. From the Middle Triassic to Late Cretaceous, accelerated burial depth triggered a substantial increase in free gas content. Since the Late Cretaceous to the present, tectonic uplift has halted hydrocarbon generation, but favorable structural preservation conditions in the Luzhou Area have effectively retained free gas.

The porosity and permeability of the sand bodies in the Xihu Depression's Huagang Formation are generally poor, while locally developed high-quality reservoirs are often the key to hydrocarbon accumulation. Based on core, thin section data, electron probe, and analytical testing data, the reservoir characteristics and their main controlling factors were analyzed, and a development model for high-quality reservoirs was established. The results show that the H3 Member in the study area mainly develops ultra-low permeability reservoirs, low-permeability reservoirs, and high-permeability reservoirs, with intergranular dissolution pores being the main pore type of the high-quality reservoirs. The sandstone reservoir diagenesis includes compaction, cementation (quartz, carbonate, clay), and dissolution. During the evolution process, the reservoir has experienced acidic modification by meteoric water and hydrocarbon charging. It was found that the source and strong hydrodynamic depositional facies are favorable conditions for the development of high-quality reservoirs. Early carbonate cementation and late hydrocarbon charging modification are the keys to the protection of primary pores and the generation of secondary pores in high-quality reservoirs. The coupling of sedimentary, diagenetic, and tectonic actions in time and space controls the formation of high-quality reservoirs.

The Pearl River Mouth Basin, located in the eastern part of the northern continental margin of the South China Sea, is an important oil and gas bearing basin in China. Among them, many oil and gas fields and oil bearing structures have been found in the Zhu I Depression. The results of the second national resource assessment show that the oil and gas resources in the Zhu I Depression are dominated by oil, supplemented by natural gas, and have great resource potential. In order to systematically evaluate the hydrocarbon generation capacity of source rocks in the hydrocarbon rich sag of Zhu I Depression in the Pearl River Mouth Basin, two sets of four types of source rocks, namely, Wenchang Formation semi deep lake facies, shallow lake semi deep lake facies, Enping Formation shallow lake limnetic facies, and coal measures, were selected to conduct hydrocarbon generation simulation experiments in a semi open and semi closed system to comprehensively obtain the hydrocarbon generation dynamic model of source rocks. Under the guidance of the “genetic method” oil and gas resource evaluation method, combined with the basin simulation software, multiphase source rocks were used for the first time to fully confirm the Zhu I Depression from the thermal evolution degree of the hydrocarbon rich sag, the hydrocarbon generation history of the source rocks, and the intensity of hydrocarbon generation and expulsion. The hydrocarbon rich sag has a large amount of oil and gas resources, and these achievements provide a strong scientific basis for the further exploration and development of Zhu I Depression.

To further understand the hydrocarbon accumulation rules of the deepwater Gulf of Mexico Basin, using the seismic, drilling and geochemical test data of the study area, the tectonic-sedimentary evolution characteristics and the accumulation conditions are systematically analyzed, and the hydrocarbon accumulation model and exploration direction are discussed. The oil and gas exploration are mainly concentrated in four major geological regions, namely, basin, sub-salt, folded belt and abyssal plain, which is the result of the complex interaction between sedimentation and tectonics in Mesozoic and Cenozoic. The marine marlstones of the Upper Jurassic Tithonian and Oxford Stages are the main hydrocarbon source rocks in the deep-water area, showing the characteristics of “deep burial”, “old age” and “late hydrocarbon generation”. The reservoirs are of various types, and generally show the characteristics of “multi-layer system”, “new age”, “fast burial” and “high pore permeability”. The penetrating transportation channels associated with salt rock movement and accompanying fault activity are crucial for oil and gas transportation. There are three types of deep-water tectonic circles: structural traps with four-way closures, combined structural/stratigraphic traps with three-way closures, and stratigraphic traps. To sum up, three reservoir-forming combination models were formed, which are “early source fault communication—late fault or salt-body flanking closure—high level accumulation”, “subsalt overpressure and low temperature—fault communication—salt-body/salt-welding occlusion accumulation” and “near-source vertical migration—lateral transport adjustment—dominant structure accumulation”. The Wilcox sandstones in sub-salt and folded belt, Jurassic aeolian sandstones in the eastern basin and abyssal plain are favorable exploration targets in the deepwater Gulf of Mexico Basin.

To investigate the fracture characteristics and layer-crossing propagation law of CO₂-hybrid fracturing in laminated shale, CO₂-hybrid fracturing experiments were conducted with the full-diameter Jiyang Sag Shale, and the Cohesive unit model was used to simulate the effect of pre-CO₂ injection rate on layer-crossing propagation. The results show that: 1) CO₂ fracturing is easy to activate beddings and natural fractures, which provides conditions for the formation of complex cross fractures in subsequent hydraulic fracturing, and the fracture volume increased by 24.0% with doubled pre-CO₂ injection rate; 2) The low viscosity and high permeability of CO₂ easily induce fractures to propagate along weak surfaces (beddings, natural fractures), mineral grain boundaries, and pore directions, resulting in the roughness of CO₂ fracturing fractures about 50.0% higher than hydraulic fractures; 3) With the increase of CO₂ injection rate, the ability of fracture to pass through beddings is enhanced. At low CO₂ injection rate, fracture propagation is dominated by bedding, while fracture propagation is dominated by in-situ stress at high injection rate. The research results provide the mechanism and theoretical understanding of the fracture propagation law of CO₂-hybrid fracturing of shale oil reservoir in Jiyang Sag. Compared with conventional fracturing in the field, the stimulation volume of CO₂-hybrid fracturing increased by 12.2%, capacity by 33%, and decline rate of oil production decreased by 6.8%.

To prevent secondary hydrate formation and enhance wellbore flow, the mathematical model to investigate the temperature and pressure in the development of the argillaceous natural gas hydrate. With the moderate sand control technique, this model predicted the temperature and pressure profiles along the well considering the sand particle size effect and the JouleThompson effect on heat transfer within the hydrate production wellbore. According to the moderate sand control principle, the paper also analyzed how the size of produced formation sand and the wellbore size could affect the secondary formation of natural gas hydrates in the wellbore. The effect is quantitatively described in the sensitivity analysis. Considering the development environment of NGH, several key factors were selected in the sensitivity analysis including produced formation sand size, wellbore diameter and thickness, production rate, thermal conductivity, and NGH formation depth. The analysis recommended the produced formation sand as less than 30 μm and the wellbore thickness as 0.389 m to reduce the risk of NGH secondary formation. The risk secondary NGH formation for shallow reservoir depth was higher than that for deep reservoir. The calculation verified that the installation of local heating electrode could effectively reduce the secondary formation risk of hydrate near the mud line. The research results of this paper provide theoretical support for fine sand control and well structure design of deep sea hydrate reservoir production.

When used as the cushion gas of underground gas storage, CO₂ can maintain the stability of pressure inside the gas storage, prevent working gas from escaping from the bottom edge, prevent edge and bottom water from invading, and provide power for gas production. However, the injected CO₂ will mix with natural gas, and the strong injection and production in the gas reservoir may cause the fluctuation of CO₂ and CH₄ mixing zone, thus affecting the purity of produced gas. In this paper, mixed gas experiment of sand filling vessel and multiple injection and production experiment of CH₄ and CO₂ were carried out to study the mixed gas characteristics of CO₂ and natural gas as well as the influence of different working cycle and working system on the mixed zone. The numerical simulation results were tested with laboratory experiment results. The experimental results show that under the same production system, with the increase of injection-production cycle, the mole fraction of CO₂ in the sampling gas also increases gradually at very small scale and the mixing zone moves up slowly. The mole fraction of CO₂ in the sample gas decreases with the increase of the gas production rate. The gas production rate will have an impact on the development of the mixing zone, but the impact is not significant.

The primary pore and secondary fracture-cave system are the main storage spaces in the fracture-cave carbonate reservoir. The fractures are the infiltration channels for oil and gas. The spatial development of each fracture-cave body is isolated, with poor connectivity, and the scale of single well control fracture-cave is limited. The proportion of oil wells with long shutdowns and low efficiency in Halahatang Oilfield has reached 41% due to small well control reserves. In the early stage, attempts have been made to treat them through repeated acid fracturing and high-pressure expansion water injection, and have achieved some results, but with a short effective period and rapid after treatment decrease for most wells. It is difficult to achieve the recovery of oil wells with small well control reserves relying solely on acid fracturing or expansion water injection. Based on the research of reservoir transformation methods in the early stage, a new method of scale acid fracturing and expansion water injection is proposed to address this issue. First, forms a high-pressure water zone near the well through expansion water injection, opens natural fractures or fractures in the formation. Then, acid pressure is used to achieve simultaneous maximization of acid etched fracture length and acid etched fracture conductivity, communicating with distant well reservoirs. After acid fracturing, large displacement water injection is directly carried out for ultra long distance etching, thereby achieving the goal of“creating fractures and finding holes”. At present, three wells have been implemented, increasing geological reserves by 460 400 tons and cumulative oil production by 47 200 tons. It is expected that the cumulative oil production during the effective period can reach 63 600 tons, providing an economically effective new method for the expansion and production increase of inefficient wells in fractured carbonate reservoirs.

Accurate prediction of gas load holds significant practical value for maintaining the dynamic balance between gas supply and demand. With advancements in artificial intelligence technology, gas load forecasting algorithms have undergone substantial development. This study first categorizes forecasting periods into three distinct phases: short-term (ST), medium-toshort-term (MST), and medium-to-long-term (MLT). From an algorithmic perspective, we systematically analyze six representative methods including eXtreme Gradient Boosting (XGBoost) for ST forecasting, two approaches such as Long Short-Term Memory (LSTM) networks for MST forecasting, and two techniques including Prophet for MLT forecasting, and evaluate their advantages, limitations, and application scenarios. Through empirical validation using operational data, we conduct multidimensional comparative analysis of 12 selected models. Our experimental framework encompasses critical aspects including dataset construction, data preprocessing, extrapolative prediction, parameter optimization, and model evaluation across different temporal scales. Finally, we propose forward-looking perspectives on future research directions in gas load forecasting, particularly focusing on practical applications in natural gas dispatch management. This comprehensive investigation provides valuable references for advancing algorithmic research in gas load prediction and its implementation in smart energy management systems.

In response to the adverse impacts of oil well failures on production efficiency and operational safety in oilfields, this study focuses on rapid and accurate diagnosis and effective mitigation of such failures in complex environments. An intelligent framework for oil well fault diagnosis and disposal based on large models is proposed. First, a multi-modal association rule mining algorithm (M–ARMA) is designed to extract association rules between abnormal data and fault types from multimodal data sources such as pressure, load, and indicator diagrams of oil wells. Second, the XLNet-DC model is proposed to automatically extract fault handling rules from oil well failure reports and maintenance logs. Finally, a knowledge graph for oil well fault diagnosis and handling is constructed, and inference rules for abnormal fault handling are established through entity matching. By integrating real-time faults detected by the oil well monitoring module, the framework enables intelligent fault diagnosis and disposal via knowledge-based reasoning. Experimental validation in an oilfield demonstrates that the proposed method achieves an F₁ of 93% in knowledge extraction and a fault diagnosis accuracy of 96%. The framework effectively supports the integrated matching of accurate fault identification with appropriate handling strategies, thereby enhancing the safety and stability of oilfield production.

The ultra deep fault controlled fracture vuggy carbonate reservoir has strong heterogeneity and obvious spatial dispersion distribution characteristics. Different from clastic rock reservoirs, the geological characteristics of reservoirs between wells and the development effects in different development stages are different. There is no standardized method to scientifically evaluate the development effects of this type of reservoir in different development stages. Aiming at the typical fault zone of Fuman Oilfield, an overall technical approach to grading and evaluating the development effectiveness of single well (well group units) in the natural energy development stage and water injection development stage has been proposed. Five key principles for determining the development effectiveness evaluation index system have been clarified, and four key indicators for the natural energy development stage and nine key indicators for the water injection development stage of this type of reservoir have been selected. A comprehensive evaluation index system for different development stages was established using analysis hierarchy process. This research method and technical process can provide standardized and scientific research ideas in the process of building development effectiveness grading evaluation index systems for different development stages in other types of oil reservoirs. It can provide technical support for searching for potential zones in developed areas and optimizing development methods, and has good prospects for promotion and application.

Oil and gas pipeline risk assessment is a complex systems engineering project. To address the limitations of traditional risk assessment methods when applied to China's oil and gas pipelines, this paper proposes a new method called“negativepositive coupling risk assessment ” . Based on the actual operating conditions of China's pipelines, this method innovatively integrates positive factors that enhance pipeline safety and negative factors that pose threats into the same assessment framework. It focuses on analyzing the coupling mechanism between these factors, establishes a framework system for failure probability indicators and a framework system for failure consequence indicators in the research, provides a specific score calculation method, and adds correction index values for coupling effects. Through the application of an example of a natural gas pipeline in southwest China, the feasibility and effectiveness of this method are verified. The correction range of the coupling effect on the risk value is between 6% and 14%. Applying this method can accurately identify key risk control points and provide a clear direction for risk mitigation decisions, thereby effectively preventing intermediate events and major accidents. It holds important practical guiding significance for reducing the accident probability of China's oil and gas pipelines and ensuring the safety of energy arteries.

Friction coefficient is a key parameter in calculating the drag force when drilling and is obtained by back-calculation based on the data such as weight on bit and hook load, enabling studies on torque and drag. However, few studies have deeply investigated the influencing factors and variation patterns of the friction coefficient between the drillstring and borehole from the perspectives of friction mechanism, microstructure, and the mixed lubricating medium. To address this issue, a friction experimental platform is built and the studies on the influences of drilling technologies (gas drilling and mud drilling), borehole condition (casing and rock borehole) and the diameter, characteristic and distribution pattern of cuttings are made. The research shows that the geometric irregularity of cuttings becomes more pronounced with increasing particle size, serving as the primary factor controlling friction coefficient variations. Compared to the rough surface of borehole rock, the friction coefficient of casing is much lower, suggesting that improving open-hole quality can reduce drag. Additionally, the envelop effect of cuttings bed significantly increases the friction coefficient. The friction coefficient value is within the range of 0.44～0.58 when gas drilling and it is 0.25～0.45 in casing, 0.35～0.55 in borehole rock when mud drilling.

Gel water plugging is the main technical method for recovery in the middle and late development of Tahe Oilfield. As the reservoir temperature and salinity continue to increase, the water plugging effectiveness of a single gel system is low, and its system development and use of water plugging materials urgently need to be optimized and improved. In this regard, this paper is based on the research of two independently developed sets of high temperature resistance, high salinity and dilution resistance water plugging systems. Through infrared, thermos-gravimeter, rheology and other analyses, the dilution resistance and compatibility of gel materials are systematically evaluated. At the same time, based on core experimental simulation, a dynamic plugging model for the collaborative application of the two gel systems is proposed to compound water plugging to further improve the dynamic plugging rate and plugging effect. Results show that the two gel systems can be applied to high temperature conditions of 140 ℃ and have good dilution resistance in water with a salinity of 24×10⁴ mg/L. While ensuring good compatibility of the two gels, they are used synergistically. Their excellent erosion resistance makes the collaborative water plugging rate greater than 99%. Studies have shown that different gel systems with good compatibility can combine to block water and have good application potential in high temperature and high salinity environments.