The submarine fan is an important reservoir for oil and gas in deep water areas. The differences in reservoir quality have a significant impact on the differential accumulation and exploitation of oil and gas. Previous studies have conducted extensive research on the differences in reservoir quality of submarine fans. However, the characteristics and distribution patterns of reservoir quality differences within submarine fans under a steep continental slope background are still unclear. This paper takes the Oligocene submarine fan reservoir in the X gas field of the Rovuma Basin in East Africa as the research object. By integrating core, well logging and seismic data, an in-depth study has been carried out on the control of reservoir quality differences and distribution patterns of submarine fan sedimentary microfacies and lithofacies under the steep continental slope background. The results show that the changes in reservoir quality within the submarine fan are mainly controlled by rock texture, lithofacies (association) and sedimentary microfacies under the circumstance of weak diagenesis. Grain sorting and clay content mainly control the porosity and permeability of the reservoir, respectively, but the relationship between grain size and reservoir properties is very complex. In sand-rich lithofacies, fine sandstones have the highest porosity due to their good sorting, and massive gravel-bearing coarse sandstones have the highest permeability due to their low clay content. Under the steep continental slope background, the submarine fan sedimentary microfacies are arranged in the order of muddy channel-sandy channel-lobe main body-lobe edge along the source direction, resulting in the source-directional differences in reservoir quality in the order of “poor, good, and poor”. The proximal muddy channel consists of fine-grained and clay-rich lithofacies, with overall poor physical properties. In the middle position, the sandy channel and lobe main body change to massive gravel-bearing coarse sandstone lithofacies and medium-coarse sandstone lithofacies, with low clay content and improved to good physical properties. Among them, the reservoir quality of the sandy channel is better than that of the lobe main body. The internal high porosity and high permeability zones of the sandy channel are in the form of elongated lenses, while the relatively high porosity and high permeability areas of the lobe main body are in the shape of lobes. The distal lobe edge changes to fine-grained lithofacies (fine-medium sandstone, fine sandstone) with increased clay content and gradually deteriorated physical properties.

The practice of oil and gas exploration and development shows that the transformation from “outside source” to “inside source” is an inevitable choice for the sustainable development of petroleum industry. Recently, the breakthrough of unconventional oil and gas in semi-deep lacustrine facies shale in the Qingshankou Formation (K₂qn) in the northern Songliao Basin has proved that it has broad resource prospects. The sedimentary paleoenvironment controls the accumulation of organic matter and the distribution of lithofacies, which is the basis for the prediction of shale oil desserts. In this paper, by means of experimental methods of biomarkers and element geochemistry, parameters such as paleoproductivity, paleoreoxidation, and paleosalinity of the lake basin in the northern Songliao Basin were recovered to clarify the paleoclimate evolution characteristics during the formation of Qingshankou Formation, and to compare the paleoenvironment with that of other major shale oil and gas resource enrichment basins in China. The biomarker compounds in the Qingshankou Formation samples predominantly exhibit a unimodal distribution of n-alkanes, with major peaks at nC₁₈, nC₁₉, nC₂₀, and nC₂₁. The Pr/Ph ratio ranges from 0.44 to 1.31, with an average value of 0.87, indicating a general dominance of phytane. Among the major elements, CaO, Na₂O, and P₂O₅ are relatively enriched, while among trace elements, Sr shows the highest enrichment, with Ba, V, Cr, Ni, Cu, Rb, and Y being relatively depleted. The research results indicate that the Songliao Basin developed under warm and humid paleoclimate conditions. Among the sub-basins, the Gulong Sag was relatively more humid compared to the Sanzhao Sag. The lower section of the Qingshankou Formation exhibited warmer and more humid characteristics compared to the middle and upper sections. Influenced by the transgression of the Paleo-Pacific Ocean from the east, the salinity of the lake basin water was relatively high, with a higher degree of salinization observed in the eastern Sanzhao Sag. During the depositional period of the Qingshankou Formation in the northern Songliao Basin, overall paleoproductivity levels were high. The basin predominantly exhibited a dysoxic to anoxic reducing environment, which provided favorable conditions for the accumulation and preservation of organic matter.

Seismic petrophysical inversion is an effective method for reservoir physical property evaluation. Direct prediction of reservoir parameters from seismic data has lower uncertainty and higher accuracy than estimation of reservoir parameters from seismic elastic parameters. However, at present, there is little discussion on the establishment of initial model in direct reservoir parameter inversion. A reasonable initial model can not only improve the accuracy of inversion results but also reduce the calculation cost of inversion process. To solve this problem, this paper proposes a seismic reservoir characterization method based on pre-stack and post-stack joint inversion, which combines post-stack impedance inversion and statistical rock physical model to provide a reliable initial model for pre-stack seismic rock physical inversion, and makes full use of the high signal-to-noise ratio of post-stack seismic data and the high resolution of pre-stack seismic data to improve the stability and accuracy of reservoir parameter inversion. Firstly, the critical porosity model is calibrated based on the existing logging data, and the reservoir parametric reflection coefficient formula is constructed based on Zoeppritz reflection coefficient equation, which establishes the direct relationship between seismic data and reservoir physical properties. Then the P-wave impedance is obtained by post-stack inversion, and the initial model of reservoir physical parameter inversion is obtained by using the statistical petrophysical model obtained from logging data. Finally, based on Bayesian framework and Cauchy prior constraints, the inversion of physical property parameters such as porosity, shale content and water saturation from pre-stack seismic data is realized. The synthetic tests show that the superior anti-noise performance of post-stack impedance can provide a reliable initial model for reservoir parameter prediction, and can significantly improve the accuracy of physical property inversion. The field data test verifies the advantages of this method in improving inversion accuracy and enhancing lateral continuity in direct estimation of reservoir physical properties.

Under high operational costs and selective applicability constraints, time-lapse (4D) seismic monitoring requires a rigorous feasibility assessment before implementation. The critical aspect of this analysis involves predicting post-production changes in formation elastic parameters, which are influenced by complex factors including reservoir temperature variations, pore pressure changes, and alterations in rock frame properties during hydrocarbon production. To achieve a quantitative evaluation of time-lapse seismic feasibility, a methodological framework based on rock physics modeling has been established, using several shallow, unconsolidated sandstone reservoirs in the Bohai Bay Basin as representative examples. The targeted sandstones exhibit high porosity and weak cementation, requiring specialized modeling approaches. Based on the geological background of the target areas, sedimentary environment analysis and burial history reconstruction are integrated with rock physics techniques to build geologically constrained models. These models facilitate the quantitative description of petrophysical characteristics under varying burial and diagenetic conditions. Based on the constructed rock physics models, evaluations of rock frame stiffness and pore fluid properties are conducted, and elastic parameter variations caused by reservoir production are predicted. Forward seismic modeling is then applied to assess the detectability of time-lapse seismic signals under different acquisition scenarios. Given the limited thickness of the target reservoirs, wedge-shaped model simulations are employed to analyze the sensitivity of time-lapse seismic responses to changes in formation thickness. The overall feasibility of time-lapse seismic application is assessed from three dimensions: geological conditions, rock physical properties, and seismic detectability. Results indicate that most studied reservoirs exhibit favorable geological frameworks and competent rock skeletons. However, the nature of the pore fluids, especially hydrocarbon composition and phase behavior, emerges as the critical factor influencing the effectiveness of time-lapse seismic monitoring. Light oil reservoirs show greater potential for successful monitoring due to more significant impedance contrasts. Among the studied cases, the reservoir exhibiting the highest suitability for time-lapse seismic monitoring is selected for further analysis using existing seismic datasets. Time-lapse seismic data matching processing and 4D response evaluation are performed to validate the reliability of the feasibility assessment framework. The findings demonstrate that the proposed approach can provide robust support for evaluating the feasibility of time-lapse seismic monitoring in shallow, unconsolidated sandstone reservoirs in the Bohai Bay Basin. These insights contribute valuable guidance for future applications of 4D seismic in similar geological settings, offering meaningful implications for both petroleum geology and reservoir engineering disciplines.

The Tarim Basin, functioning as China's strategic hydrocarbon resource succession zone, encounters globally recognized technical bottlenecks in the exploitation of deep/ultra-deep reservoirs. A comprehensive chronological analysis is conducted on the development trajectory of stimulation technologies for ultra-deep hydrocarbon reservoirs in the Tarim Oilfield, particularly highlighting stimulation technology breakthroughs implemented in the field’s dual primary production zones: For complex carbonate reservoirs in ultra-deep intracratonic basins, an innovative integrated design approach for fracture-cavity-system identification and stimulation was proposed; for ultra-deep fractured classic reservoirs in the Kuqa piedmont zone, a series of high-efficiency stimulation technologies were developed. The research has achieved three major technological breakthroughs: First, the successful development of high-temperature resistant acid systems has significantly enhanced stimulation effectiveness in ultra-deep reservoirs; second, the breakthrough in high-density weighted-fracturing fluid technology provides critical support for ultra-deep well stimulation; third, continuous innovations in supporting process technologies have established a solid foundation for efficient development of ultra-deep oil and gas reservoirs. Integrating exploration trends with development challenges of ultra-deep oil and gas reservoir in the Tarim Basin, the paper addresses the production demands and existing technical deficiencies in reservoir stimulation, including: the fundamental laboratory research on deep/ultra-deep reservoir stimulation, artificial fracture propagation mechanisms, development gaps in novel stimulation fluids, zonal isolation tools, temporary plugging materials and supporting application techniques, limitations in real-time monitoring and interpretation technologies for stimulation operations. Six key technical recommendations are proposed: (1) Establishment of an ultra-high temperature/pressure experimental platform to conduct fundamental research on rock mechanics, fluid flow, and conductivity testing; (2) Investigation fracture propagation mechanisms in high-stress complex reservoirs and develop a multi-physics coupled fracture growth model; (3) Development of high-performance acid systems resistant to 200 °C, with breakthroughs in weighted, low-friction, thermal-stable, and controlled-acid-generation technologies; (4) Development of engineer stratified stimulation tools (including diverting agents and supporting techniques) to optimize treatment in interbedded formations; (5) Enhancement of “multi-cluster limited-entry” fracturing for ultra-deep horizontal wells to improve fracture-controlled reserves; (6) Implemention of real-time fracture diagnostics using fiber-optic monitoring and develop high-temperature downhole monitoring tools. This study not only systematically synthesizes the stimulation technology framework for “triple-ultra” (ultra-deep, ultra-high temperature, ultra-high pressure) reservoirs in the Tarim Oilfield, but also establishes critical technological foundations for China’s 10 000-meter-depth reservoir stimulation endeavors. The research outcomes provide significant theoretical value and engineering guidance for promoting efficient development of deep hydrocarbon resources in China, while the innovative technological approaches may also serve as valuable references for global oilfield development under analogous geological conditions.

The successful development of shale oil and gas formations mainly depends on engineering measures such as extended-reach horizontal drilling and high-volume fracturing, which enable high-quality geological sweet spots in long horizontal shale oil and gas formations to extract more industrial production capacity. Among them, drilling is the most effective and direct technical means to communicate engineering and geology. The drilling geological environment is a significant factor influencing the drilling engineering process, including both geological factors of the formation and the mutual influence factors between drilling environment and geological environment. In order to improve the high-quality sweet spot sweet-spot encounter rate, facilitate fracturing, and reduce engineering risks, this paper proposes wellbore trajectory optimization control technology for shale oil and gas formation production increase, safety, and efficiency. By analyzing the geological environmental factors of shale oil and gas formations, the models of geological sweet spot evaluation, geological risk identification, and geological engineering integration application have been formed. Based on these models, three drilling wellbore trajectory optimization control technologies have been proposed: ① Control the horizontal drilling position according to the changes of geological sweet spots in the formation space, and form trajectory control technologies that optimize drilling encountering sweet spot layers and enhance initial production (IP) rates; ② optimize the drilling direction based on the fracturing properties of engineering sweet spots, and trajectory direction optimization technology to improve the fracturing response characteristics of shale oil and gas formations; ③ To mitigate drilling risks, trajectory control techniques are developed to ensure the safety of drilling in shale oil and gas formations and reduce drilling engineering risks. Wellbore trajectory optimization control technology is one of the key technologies for achieving geo-engineering integration, which improves the efficiency of fast drilling and completion of long horizontal wells and high-volume fracturing, as well as increase the sweet-spot encounter rate rate and development efficiency of geological sweet spots.

The Linxing gas field was selected as the research object, where weak bedding planes represent typical features and significantly influence hydraulic fracture propagation. This study provides valuable insights on hydraulic fracture propagation in bedded shale formations and offers guidance for optimizing fracturing techniques. The characteristics of shale featuring bedding planes were examined by utilizing rock mechanics experiments and direct shear tests. Considering the cementation strength and friction properties of bedding planes, a computational subroutine was developed to characterize the contact behavior for bedding planes. A 3D Finite Element Method-Cohesive Zone Model (FEM-CZM) has been established for multi-field coupling analysis of stress-damage-fluid flow, specifically incorporating bedding planes. This model incorporates a contact constitutive relationship that accounts for both friction and cementation strength of the bedding. A comprehensive and systematic quantitative analysis is conducted to investigate the influence of various factors on bedding shear slip and the propagation of hydraulic fractures. These factors include the initial opening of bedding fractures, friction coefficient, cementation strength, number of bedding planes surrounding the wellbore, and fracturing operation parameters. The results indicate that the presence of weakly bonded bedding planes leads to complex fracture propagation patterns involving both tensile and shear fractures. Bedding plane apertures serve as preferential flow pathways for fracturing fluid, significantly inhibiting fracture propagation. When the bedding aperture increases to 300 μm, the fractures are unable to cross bedding planes, which limits the fracture scale. Compared to the bonding strength, the bedding friction coefficient plays a more dominant role in determining whether fractures penetrate. Higher friction coefficients facilitate the penetration, regardless of whether the bedding planes are bonded or not. The penetration probability increases exponentially as the friction coefficient rises. In contrast, with lower friction coefficients and weakly bonded bedding planes, fractures are intercepted, while higher cementation strength allows for effective penetration. Furthermore, with a rise in the number of bedding planes, the shear fractures along these beddings expands considerably, which results in a more intricate fracture pattern. The shear failure of multiple bedding planes restricts the development of tensile-dominated fractures, which reduces the efficiency of reservoir stimulation. Optimizing fracturing fluid injection, increasing high-viscosity fracturing fluid volumes, and raising injection rates can enhance vertical fracture propagation and improve the stimulated reservoir area. Further validation of the influence of bedding planes on fracture propagation is provided by analyzing distributed temperature sensing (DTS) profiles, as well as the post-fracturing performance in Linxing.

Unconventional shale oil is characterized by nanoscale pores, heterogeneous pore structures, diverse mineral compositions, non-uniform wettability, and multiple fluid types, resulting in complex multiphase flow behaviors in shale porous media that require further investigation. In this study, a nanoscale multicomponent and multiphase lattice Boltzmann method is employed to simulate oil-water two-phase flow in heterogeneous porous media with heterogeneous wettability and structure. The effects of transverse/longitudinal structural heterogeneity, capillary number and nanoscale effects on the oil-water flow and relative permeability are investigated. The results indicate that due to the higher capillary resistance in the transverse porous media, the relative permeability of the water phase in the transversely heterogeneous porous media is lower than that in the longitudinally heterogeneous porous media. As the capillary number decreases, capillary resistance becomes dominant, and the viscous driving force is insufficient to overcome the capillary forces, making it difficult for oil and water to flow. Consequently, the relative permeabilities of both oil and water phases decrease, and more fluid becomes trapped due to capillary resistance. The presence of an oil film on the solid wall induces liquid-liquid slip, which significantly enhances water flow. This enhancement effect outweighs the weakening effect caused by viscosity heterogeneity. As a result, when nanoscale effects are considered, the relative permeability of the water phase increases.

Coiled tubing drag acidizing is a commonly used diversion technique in carbonate reservoir horizontal wells. However, due to challenges such as long wellbore length, strong formation heterogeneity, and uneven damage distribution, predicting acidizing effectiveness remains uncertain. To address this, a radial dual-scale wormhole propagation model and a numerical model of coiled tubing drag acidizing were developed to simulate the evolution of acid etching patterns and the mechanism of damage removal under varying injection parameters. Field data from the X oilfield in Iraq were integrated for process optimization. Simulation results show that as the acid injection rate increases, acid etching morphologies evolve from conical pores to dominant wormholes, branched wormholes, and eventually uniform dissolution. Dominant wormholes require the least acid volume and exhibit the highest propagation efficiency. Wormhole length increases significantly with acid volume intensity, extending from 0.55 m to 1.42 m as intensity increases from 0.2 to 0.8 m³/m. Greater damage depth and lower permeability contrast lead to poorer acidizing outcomes. Based on the analysis, when the damage depth is less than 0.5 m, an injection rate of 0.5 m³/min and an acid intensity of 0.3~0.4 m³/m are recommended. For damage depths around 1 m, the recommended rate is 1 m³/min with an acid intensity of 0.4~0.7 m³/m. Field results confirm that combining coiled tubing drag acidizing with near-heel pinpoint injection can enhance well productivity by 2~5 times, outperforming other acid placement strategies. This study provides theoretical and practical guidance for optimizing acidizing parameters and operational design in carbonate long horizontal wells.

In drilling engineering, the analysis of wellbore stability is directly related to the design of wellbore structure, the design of drilling fluid density window and the safety of drilling operations. Traditional strength criteria, due to mostly linear assumptions and the neglect of the intermediate principal stress effect, are difficult to accurately characterize the nonlinear failure characteristics of rocks under deep and complex geological conditions. Therefore, the selection of an appropriate strength criterion is the key to accurately evaluating wellbore stability. This paper uses an improved three-dimensional Hoek-Brown strength criterion and combines theoretical research with model application to establish a wellbore stability evaluation model that is more in line with actual working conditions. The research results show that this criterion not only retains the nonlinear characteristics of the Hoek-Brown strength criterion in the meridian plane, but also considers the influence of the intermediate principal stress on rock strength. The yield surface of the improved three-dimensional criterion in the principal stress space is a conical surface, and the yield curve satisfies the properties of being outwardly convex, smooth and closed. Through the comparative analysis of the true triaxial test data of six different rocks, it is proved that this criterion has good applicability to various rocks. When this criterion is applied to the wellbore stability analysis of the Jialingjiang Formation limestone strata in the Tongluoxia Gas Field in the eastern Sichuan Basin, the calculated collapse pressure equivalent density is 1.16 g/cm³. When drilling along the direction of the maximum horizontal principal stress, the collapse pressure equivalent density is the lowest, which is in line with the actual working conditions and is superior to the other four traditional strength criteria. The improved three-dimensional Hoek-Brown strength criterion provides a more accurate and practical method for wellbore stability analysis.

Distributed fiber optic monitoring in adjacent wells has increasingly become an essential technique for fracture surveillance during hydraulic fracturing of unconventional oil and gas reservoirs. Developing forward models for distributed fiber optic strain response in adjacent wells is of significant importance for understanding the mechanism of fiber response and for the inversion of fracture geometries. However, existing forward interpretation models face limitations from insufficient flexibility in the selection of fracture propagation models, and by computational inefficiency caused by grid-based discretization, especially when high precision is required. To address these limitations, this study presents a semi-analytical stress-displacement field model for simulating fracture propagation with arbitrary aperture and geometric shape. Based on this, a forward modeling framework for adjacent well distributed fiber optic strain response is established. Using a penny-shaped fracture as a representative example, the stress field around the fracture is calculated and benchmarked against the classical Sneddon analytical solution. A forward simulation of fiber optic strain response for a scenario where a horizontal adjacent well monitors a vertically oriented elliptical fracture is conducted. The results are compared with the forward-modeled strain response from the Displacement Discontinuity Method(DDM). The results reveal strong consistency between the semi-analytical model and both the analytical and DDM solutions in classical benchmark cases, confirming the model’s validity and applicability. The model is further coupled with various fracture propagation models and applied to the interpretation of real field data. In particular, distributed fiber optic monitoring results from Stage 19 of Well B1H and Stage 20 of Well B2H in the Hydraulic Fracturing Test Site 2 (HFTS-2) project in the United States are analyzed. The modeling results show that the proposed approach accurately reproduces the characteristic patterns observed in field fiber data. For Stage 20 of Well B2H, which exhibits higher-complexity response characteristics, the model provides a closer match to observed details and temporal evolution compared with the DDM-based approach. In conclusion, this study establishes a semi-analytical forward modeling approach for fiber optic strain in adjacent wells under arbitrary fracture aperture and geometry, significantly reducing computational cost and improving efficiency. The model’s flexibility enables seamless integration with a variety of fracture propagation models, enhancing its capacity to accurately capture complex fracture behaviors observed in field monitoring. This provides a powerful tool for detailed interpretation and analysis of distributed fiber optic data in adjacent well applications.

Low-frequency distributed acoustic sensing in adjacent wells, a recently emerged fracturing monitoring technology, enables detailed diagnosis of hydraulic fractures. To promote industry understanding of recent advances in low-frequency distributed acoustic sensing technology for hydraulic fracture monitoring and facilitate its large-scale field application, this paper begins with the principles of distributed acoustic sensing. It briefly explains the sensing mechanism and well deployment methods, systematically summarizes research progress in numerical simulation, physical modeling, and field applications during hydraulic fracturing, and concludes by outlining future development directions for low-frequency distributed acoustic sensing technology. Research findings indicate that: ①Low-frequency fiber-optic acoustic sensing technology for hydraulic fracturing delivers high precision and real-time monitoring capabilities. This technology is increasingly being deployed for field fracture monitoring and has garnered significant attention from researchers worldwide. Disposable fiber optic systems offer distinct advantages including simplified deployment, low cost, compact footprint, and excellent value proposition. They represent a promising primary solution for future offset-well fracturing monitoring. Mitigating fiber slippage artifacts’ impact on strain response is therefore paramount for enhancing strain data fidelity in fiber optic sensing applications. ②Forward modeling primarily involves comparative analysis of simulated fiber optic strain fields with actual monitoring data to qualitatively characterize strain patterns. This establishes correlations between distinct fracture propagation types and their corresponding strain signatures, enabling interpretation of hydraulic fracture geometry and growth modes in offset wells. Current strain interpretation models predominantly consider two monitoring configurations: horizontal and vertical offset wells. However, these models fail to characterize fracture deflection induced by stress shadowing, resulting in discrepancies with field monitoring observations. Future work urgently requires developing sophisticated multi-fracture forward models that incorporate stress interference effects and fluid partitioning mechanisms to provide reliable guidance for field data interpretation. ③Inversion modeling primarily utilizes the Displacement Discontinuity Method(DDM) to construct fracture propagation models and solve for fracture dimensions. Current solution approaches include Least Squares, Picard iteration, Levenberg-Marquardt (L-M) method, and the Delayed Rejection Adaptive Metropolis (DRAM) algorithm. However, none can simultaneously invert fracture geometric parameters in all three spatial dimensions. Future inversion research must focus on optimizing solution algorithms, where effectively mitigating the impact of solution non-uniqueness will be the primary research focus for subsequent algorithmic enhancements. ④Physical simulation experiments primarily integrate distributed optical fiber interrogators based on Optical Frequency Domain Reflectometry (OFDR) technology with True Triaxial fracturing apparatuses to monitor fracture propagation. However, current experimental parameter configurations still fall short of fully replicating field conditions. Optimizing fiber deployment methodologies across diverse rock specimens and advancing the interpretation of laboratory-derived fiber optic data represent critical research priorities for future physical simulation studies. The study concludes that offset-well fiber optic monitoring demonstrates significant potential for interpreting hydraulic fracture dimensions. This technology holds considerable promise as a key enabling technology for addressing critical bottlenecks in unconventional resource development.

Buried pipelines are prone to external corrosion perforation, and leakage during service. Accurate prediction of external corrosion rate is of great significance for formulating reasonable pipeline maintenance strategies. By sorting out the factors affecting the external corrosion rate of pipelines, soil properties, stray currents, cathodic protection, and physicochemical properties were identified as the main influencing factors, and 60 sets of relevant external corrosion data were collected along a gathering pipeline in a certain region of China. Subsequently, corrosion information was extracted through multi-physics and data-driven approaches, and a Physics Guided Neural Network (PGNN) model based on physical mechanism guidance was constructed. On the basis of the conventional loss function, this model introduces physical mechanism constraints as penalty terms, adjusts corrosion factors and retrains the model to ensure that the training direction conforms to the corrosion mechanism. Genetic Algorithm (GA) is used to optimize hyperparameters, and the GA-PGNN corrosion rate prediction model is formed. Finally, Shapley Additive Explanations (SHAP) analysis quantifies to measure the influence of corrosion characteristics on corrosion rate from both global and local perspectives. The results demonstrate that compared to conventional Back Propagation (BP) and GA-BP models, the GA-PGNN model achieves superior performance with Mean Absolute Percentage Error (MAPE), Mean Squared Error (MSE), and correlation coefficient (R²) of 3.71, 1.51×10⁻⁵, and 0.9935, respectively. The GA-PGNN model exhibits smaller and more balanced mean absolute SHAP values, indicating consistent dependency on diverse corrosion factors and effective utilization of information from each factor. Conversely, both conventional BP and GA-BP models fail to capture accurate corrosion mechanisms, occasionally yield conclusions contradictory to physical principles, and predictions show significant randomness and instability. The GA-PGNN framework provides actionable insights for enhancing the integrity management of buried pipelines.

With the optimization of China ‘s energy structure, the consumption and import volume of Liquefied Natural Gas (LNG) as a clean energy have continued to increase. However, the light hydrocarbons containing ethane and above not only affect calorific value and metering, but also restrict the comprehensive utilization efficiency of resources. Based on the review of traditional processes such as US patent US0188996A1, US7069743B2 and Chinese patent CN1318543C, a new process for LNG light hydrocarbon recovery based on Direct Heat Exchange (DHX) is proposed. This process introduces a heavy contact tower to achieve secondary fine separation of methane and light hydrocarbons, eliminates the flash tower in the traditional process, and optimizes the heat exchange network and energy consumption distribution through designs such as stepwise utilization of rich liquid thermal energy and energy recuperation within the deethanizer. Process simulations were conducted based on the PR (Peng Robinson) state equation and HYSYS software. Comparative analyses covered energy consumption, product quality, exergy, heat exchange network, etc. The objective function optimization was achieved by combining the response surface experimental design and the NSGA-II (Non-dominated Sorting Genetic Algorithms-II) algorithm. The results show that if only methane is extracted from LNG rich liquid, the energy consumption of the process proposed in this paper is reduced by 35.9%, 46.4% and 44.9% respectively compared with the US patent US0188996A1, the US patent US7069743B2 and the Chinese patent CN1318543C. The high calorific value of the process in this paper can be reduced to 34.16 MJ/m³, meeting the quality requirements of Class I natural gas. The total exergy loss is 7171 kW, and the exergy efficiency of the system is 57.4%. Heat exchange network analysis shows that its minimum heat exchange temperature difference and logarithmic mean temperature difference are smaller, and the heat integration degree is higher. After optimization by the NSGA-II algorithm, with little change in ethane yield, the total energy consumption can be reduced from 16,863 kW to 16,701 kW. With little change in total energy consumption, the ethane yield can increase from 93.52% to 97.85%. The process proposed in this paper has significant advantages in reducing energy consumption, improving product quality and resource recovery rate, and can provide important theoretical support for the engineering design and on-site operation of LNG light hydrocarbon recovery.

In the context of increasing global oil price volatility and escalating supply chain risks, enhancing the stability and self-sufficiency of crude oil supply has become a strategic priority for ensuring national energy security. Extra heavy oil, characterized by abundant reserves and low cost, holds significant potential to be converted into high-quality synthetic light crude through hydrogen-based deconstruction using green hydrogen. However, the economic viability of this pathway is highly sensitive to fluctuations in key factors such as extra heavy oil procurement prices, green hydrogen production costs, and renewable electricity prices. Therefore, it is essential to develop a quantitative evaluation and optimization model under multi-dimensional uncertainty to support investment decision-making. Building on conventional techno-economic analysis frameworks, this study incorporates the effects of multi-dimensional stochastic variables by employing parameter perturbation and Monte Carlo simulation methods to construct a breakeven price model under uncertainty. Based on the volatility characteristics of extra heavy oil prices, a feedstock procurement and storage optimization model is further developed, forming a systematic evaluation and optimization framework. The results show that feedstock procurement costs and green hydrogen production costs are the primary factors influencing the distribution of breakeven prices. Under the baseline scenario, the breakeven price exhibits a right-skewed distribution with a skewness coefficient of 0.76, and the 10%~90% quantile range spans from 5537 to 7601 CNY/ton. The distribution has a long-tail characteristic, with a 5% probability of exceeding 8000 CNY/ton. Mechanistically, price increases raise marginal costs and shift the breakeven point to the right. Meanwhile, greater price volatility amplifies cost uncertainty, thickens the distribution tail, and increases the risk of extreme outcomes. Under a procurement and storage optimization strategy, annual cost savings of approximately 266 million CNY can be achieved, and the breakeven price distribution transitions from right-skewed to approximately normal. Compared to the baseline scenario without optimization, the probability of extreme high breakeven prices is significantly reduced, and the 10%~90% quantile range narrows by 1519 CNY/ton. Assuming a synthetic light crude market price of 7000 CNY/ton, the probability of profitability increases from 74% to 99%. Storage optimization effectively lowers the probability of high breakeven prices and enhances profit stability. In addition, reductions in green hydrogen production costs will further improve economic performance. The study also finds that investors’ varying risk preferences significantly affect their tolerance for return uncertainty, suggesting that policy design should account for such heterogeneity to enhance plan adaptability. This research provides scientific decision-making support for investment in extra heavy oil deconstruction via green hydrogen and offers a novel and practical pathway for enhancing energy security and achieving low-carbon transition under China’s carbon neutrality goals.