Search Results (1,142)

Waterlogging stress significantly impacts the growth and productivity of crops. As a traditional oil crop, sesame (Sesamum indicum L.) suffers substantial damage due to waterlogging stress. However, the mechanism underlying waterlogging stress in sesame is still unclear. In this study, we investigated the physiological indicators of two sesame genotypes under waterlogging stress. The results revealed that the activity of antioxidant enzymes in sesame was affected, with the contents of malondialdehyde (MDA) and hydrogen peroxide (H₂O₂) significantly increased. Additionally, transcriptional analysis identified a total of 15,143 differentially expressed genes (DEGs). Among them, 759 DEGs exhibited consistent differential expression across all time points, representing the core waterlogging-responsive genes. Gene Ontology (GO) enrichment analysis indicated that the DEGs were primarily associated with hypoxia, stimulus response, and oxidoreductase enzyme activities. Kyoto Encyclopedia of Genes and Genomes (KEGG) analysis revealed that these DEGs were mainly enriched in the metabolic and biosynthesis of secondary metabolites, glycolysis/gluconeogenesis, phenylpropanoid biosynthesis, MAPK signaling pathway-plant, carbon fixation by Calvin cycle, plant hormone signal transduction, and plant-pathogen interaction pathways. Furthermore, transcription factors (TFs) such as AP2/ERF, bHLH, bZIP, and WRKY may play key roles in the transcriptional changes induced by waterlogging stress. Combined with weighted gene co-expression network analysis (WGCNA) analysis and K-means clustering, a total of 5 hub genes and 56 genes were identified, including F-box protein (Sin09950 and Sin12912), bZIP (Sin04465, Sin00091), WRKY (Sin01376, Sin06113), and so on. In brief, this study explored the regulatory network involved in waterlogging stress in sesame at the transcriptome level, providing valuable insights into unraveling the molecular mechanisms of waterlogging stress and facilitating the breeding of improved waterlogging-tolerant sesame varieties. Full article

This paper describes an innovatively designed experimental method for fracturing fluid energy storage to explore the energy storage mechanism during the well shut-in process of fractured shale reservoirs. By improving the existing core clamp and adding fracturing fluid cavities and large volume intermediate containers to simulate artificial fractures and remote shale reservoirs, the pressure changes in the core during the well shut-in process were monitored under the conditions of a real oil–water ratio and real pressure distribution to explore the energy storage law of the shut-in fluid in fractured shale reservoirs. Compared to the 0.62 MPa energy storage obtained from traditional energy storage experiments (without artificial fractures or remote shale reservoirs), the experimental scheme proposed in this paper achieved a 2.45 MPa energy storage, consistent with the field’s monitoring results. The energy storage effects of four fracturing fluids were compared, namely pure CO₂, CO₂ pre-fracturing fluid, slickwater pre-fracturing fluid, and pure slickwater fracturing fluid. Due to the characteristics of a high expansion coefficient and low interfacial tension of pure CO₂, the energy storage effect was the best, and the pressure equilibrium time was the shortest. Considering factors such as comprehensive economy and energy storage efficiency, the optimal range for CO₂ pre-injection is between 20% and 30%. Based on the optimization criterion of energy storage pressure balance, it is recommended that the optimal CO₂ shut-in time be 5 h and the slickwater be 12.8 h. Considering the economic, sand carrying, and energy storage effects, and other factors, CO₂ pre-storage has the best imbibition effect, and the optimal CO₂ pre-storage range is 20~30%. The research results provide theoretical support for energy storage fracturing construction in other shale oil reservoirs of the same type. Full article

Electrofacies are log-related signatures that reflect specific physical and compositional characteristics of rock units. The concept was developed to encapsulate a collection of recorded well-log responses, enabling the characterization and differentiation of one rock unit from another. The analysis of the lateral and vertical distribution of electrofacies is crucial for understanding reservoir properties; however, well-log analysis can be labor-intensive, time-consuming, and prone to inaccuracies due to the subjective nature of the process. In addition, there is no unique way of reliably classifying logs or deriving electrofacies due to the varying accuracy of different methods. In this study, we develop a workflow that mitigates the variability in results produced by different clustering algorithms using a committee machine. Using several unsupervised machine learning methods, including k-means, k-median, hierarchical clustering, spectral clustering, and the Gaussian mixture model, we predict electrofacies from wireline well log data and generate their 3D vertical and lateral distributions and inferred geological properties. The results from the different methods are used to constitute a committee machine, which is then used to implement electrofacies-guided well placement. 3D distributed petrophysical properties are also computed from core-calibrated porosity and permeability data for reservoir simulation. The results indicate that wells producing from a specific electrofacies, as predicted by the committee machine, have significantly better production than wells producing from other electrofacies. This proposed detailed machine learning workflow allows for strategic decision-making in development and the practical application of these findings for improved oil recovery. Full article

The turbidite lobe is a significant reservoir type formed by gravity flow. Analyzing the architecture of this reservoir holds great importance for deep-water oil and gas development. The main producing zone in Z Oilfield develops a set of turbidite lobes. After more than 60 years of development, the well spacing has become dense, providing favorable conditions for detailed research on reservoir architecture of this kind. Based on seismic data, core data, and logging data, combined with the results of reservoir numerical simulation, this paper studies the reservoir architecture of turbidite lobes, displays the distribution of remaining oil in the turbidite lobes, and proposes development policies suitable for turbidite lobe reservoirs. The results show that the turbidite lobes can be classified into four sedimentary microfacies: lobe off-axis, lobe fringe, interlobe facies, and feeder channel facies. The study area is mainly characterized by multiple sets of lobes. There are feeder channels running through the south to the north. Due to the imperfect well pattern, the remaining oil is concentrated near the lobe fringe facies and the gas–oil contact. It is recommended to tap the potential of the turbidite lobes by adopting the “production at the off-axis lobes facies and injection at the lobe fringe facies (POIF)”. The study on the reservoir architecture and remaining oil of turbidite lobes has crucial guiding significance for the efficient development of Z Oilfield and can also provide some reference for developing deep-water oilfields with similar sedimentary backgrounds. Full article

Heterogeneous reservoirs are prevalent; otherwise, they are rare. The problem is detecting the degree of such heterogeneity, which has a significant impact on hydrocarbon production in oilfields. Several vertical heterogeneity measures were introduced to accomplish this task. The coefficient of variation (C_V), the Dykstra–Parsons coefficient (V_DP), and the Lorenz coefficient (L_C) are the most common static vertical heterogeneity measures. This study aimed to review these heterogeneity measures, explained how the probability of the permeability distribution affects calculations of heterogeneity measures, explained how involving the porosity affects calculations, and explained how uncertainty in V_DP values affects the estimation of cumulative oil production. In this study, 1022 plug core samples from seven wells in different sandstone reservoirs were used. The results reveal that the permeability is log-normally distributed; thus, the C_V is calculated based on the variance only. The outliers have a significant effect on the values of the C_V. The studied reservoirs are extremely heterogeneous, as evidenced by the V_DP. The proposed straight line resulting from the Dykstra–Parsons plot is rarely encountered. Weighting the central points more than the points at the tails gives V_DP values similar to those obtained from the data. An uncertainty in the V_DP values could have a considerable effect on the calculations of the cumulative oil production. The study also shows that including porosity in the calculation of the L_C leads to a decrease in the L_C values. The magnitude of the decrease is contingent upon the degree of reservoir heterogeneity and the average porosity. Above L_C > 0.7, the reservoir could be extremely heterogeneous. Full article

Gas channeling during CO₂ flooding poses a significant challenge to enhanced oil recovery (EOR) in heterogeneous reservoirs, limiting both oil recovery and CO₂ sequestration efficiency. To address this issue, a CO₂-responsive plugging gel was developed using polyethyleneimine (PEI), sodium dodecyl sulfate (SDS), and nano-silica. The gel formulation, containing 0.8% SDS, 0.8% PEI, and 0.1% nano-silica, demonstrated excellent CO₂-responsive thickening behavior, achieving a viscosity of over 12,000 mPa·s under selected conditions. The gel exhibited reversible viscosity changes upon CO₂ and N₂ injection, shear-thinning and self-healing properties, and stability under high-temperature (90 °C) and high-salinity (up to 20,000 mg/L) conditions. Plugging experiments using artificial cores with gas permeabilities of 100 mD and 500 mD achieved a plugging efficiency exceeding 95%, reducing permeability to below 0.2 mD. These results emphasize the potential of the CO₂-responsive plugging gel as an efficient approach to reducing gas channeling, boosting oil recovery, and enhancing CO₂ storage capacity in crude oil reservoirs. Full article

The study of seepage laws during microbial enhanced oil recovery helps to elucidate the mechanisms behind microbial flooding, and the use of large-scale physical simulation experimental devices can more objectively and accurately investigate the seepage laws of microbes in porous media, and evaluate the oil displacement efficiency of microbial systems. In this study, physical simulation experiments of microbial flooding were conducted via a slab outcrop core, and the biochemical parameters such as the concentration of Bacillus subtilis, nutrient concentration, surface tension, and displacement pressure data were tracked and evaluated. The analysis revealed that the characteristics of the pressure field change during microbial flooding and elucidates the migration rules of microbes and nutrients, as well as the change rule of surface tension. The results show that after the microbial system is injected, cells and nutrients are preferentially distributed near the injection well and along the main flow paths, with the bacterial adsorption and retention capacity being greater than those of the nutrient agents. Owing to the action of microorganisms and their metabolites, the overall pressure within the model increased, From the injection well to the production well, the pressure in the model decreases stepwise, and the high-pressure gradient zone is mainly concentrated near the injection well. The fermentation mixture of Bacillus subtilis increased the injection pressure by 0.73 MPa, reduced the surface tension by up to 49.8%, and increased the oil recovery rate by 6.5%. Full article

Transformers are susceptible to the influences of complex power grid systems, which may induce three-phase unbalance in transformers, thereby threatening their safety and stable operation. To better understand multiphysics interactions within a transformer under a three-phase load unbalance, a coupled multiphysics model is established and validated for an oil-immersed transformer based on the finite element method. The electromagnetic characteristics, conjugate heat transfer, and thermal stress of the transformer under three-phase load unbalance are analyzed, and the impact on the transformer’s relative aging rate is further assessed. The results show that under three-phase load unbalance, winding losses are significantly influenced by the degree of unbalance, while core losses remain almost unaffected. The maximum difference in winding losses between phases can reach 9.6 times, with a total loss increase of approximately 17.31% at a 30% unbalance degree for Case 3. The mutual heating effect between adjacent windings intensifies with the degree of unbalance, leading to higher temperatures in low-loss windings and sustaining high thermal stress and expansion. Severe three-phase unbalance (e.g., 30% unbalance degree in Case 3) can be mitigated by reducing the transformer load rate to 90%, thereby reducing the relative aging rate to about 20% of that under full load and significantly extending the transformer’s insulation life. Full article

The conventional polymer gel has high initial viscosity and short gelation time, making it difficult to meet the requirements of deep profile control in offshore reservoirs with large well spacing and strong heterogeneity. This paper evaluates the performance and core plugging capacity of novel functional polymer gels and microspheres to determine the applicability of core permeability ranges. On the heterogeneous core designed based on the reservoir characteristics of Block B oilfield, optimization was conducted separately for the formulation, dosage, and slug combinations of the polymer gel/microsphere. Finally, oil displacement experiments using polymer and microsphere combinations were conducted on vertically and planar heterogeneous cores to simulate reservoir development effects. The experimental results show the novel functional polymer gel exhibits slow gelation with high gel strength, with viscosity rapidly increasing four days after aging, ultimately reaching a gel strength of 74,500 mPa·s. The novel functional polymer gel and polymer microsphere can effectively plug cores with permeabilities below 6000 mD and 2000 mD, respectively. For heterogeneous cores with an average permeability of 1000 mD, the optimal polymer microsphere has a concentration of 4000 mg/L and a slug size of 0.3 PV; for heterogeneous cores with an average permeability of 4000 mD, the optimal functional polymer gel has a concentration of 7500 mg/L and a slug size of 0.1 PV. In simulations of vertically and planarly heterogeneous reservoirs, the application of polymer agent increases the oil recovery factor by 53% and 38.7% compared to water flooding. This realizes the gradual and full utilization of layers with high, medium, and low permeability. Full article

Dual-porosity carbonates exhibit abundant macropores and micropores, yet the mechanisms governing oil/water flow at the dual-porosity scale remain inadequately understood. This study investigates the flow behavior in dual-porosity carbonates during forced imbibition. Initially, carbonate characteristics were extracted using a random field method to generate two types of porous media. Subsequently, the multiple-relaxation-time color-gradient lattice Boltzmann method, validated by experimental and analytical solutions, was employed to systematically evaluate the effects of wettability, capillary number, and oil/water viscosity ratio on oil displacement efficiency in dual-porosity carbonates during forced imbibition. The reliability of the simulated oil displacement efficiency was verified through core waterflooding experiments. The results reveal that under water-wet conditions, fluid flow paths in dual-porosity carbonates are strongly influenced by the blockage of micrite particles at low capillary numbers, while at high capillary numbers, the fragmentation of large continuous oil droplets interacting with micrite particles leads to more unstable interfaces. Under non-water-wet conditions, dominant capillary forces enhance oil displacement within macropores of dual-porosity carbonates. Under the same conditions, water-wet conditions are more favorable for improving oil displacement efficiency. As the capillary number increases, oil displacement efficiency exhibits a pronounced non-monotonic trend under non-water-wet conditions, attributed to the alternating dominance of viscous and capillary forces. Additionally, with an increase in oil/water viscosity ratio, the decline in oil displacement efficiency is less pronounced for dual-porosity carbonates compared to single-porosity carbonates, particularly under non-water-wet conditions at high capillary numbers. Full article

This study presents a tailored nitrogen foam flooding system developed for the Mu146 block’s medium-high permeability reservoir conditions. Through systematic optimization, we establish an optimal formulation comprising 0.40% FP2398 foaming agent and 0.13% WP2366 stabilizer. The formulated foam demonstrates superior performance characteristics with a generated volume of 850 mL and extended stability duration of 1390 s, exhibiting exceptional structural integrity under oil-bearing conditions. Core flooding experiments conducted on berea cores reveal a 33.20% incremental oil recovery factor following waterflooding that achieves 53.60% primary recovery. The non-steady-state nitrogen foam huff-and-puff (NSSNFHF) field test at Well Mu146-61 shows significant reservoir response, with post-treatment analyses indicating an average chloride ion concentration increase of 540.20 mg/L and total salinity elevation of 1194.20 mg/L across five monitoring wells. These chemical signatures confirm effective volumetric sweep enhancement through the NSSNFHF field test, demonstrating a flooding-like mechanism that mobilizes bypassed oil in previously unswept zones. The field test encompassing Well Mu146-61 and four offset producers yield substantial production improvements, including a 74.55% increase in fluid production rates and a sustained oil yield of 1.80 tons per day. The validity period of the NSSNFHF field test is more than 12 months. The technology demonstrates dual functionality in conformance control and enhanced recovery, effectively improving both oil productivity and ultimate recovery factors. Full article

Complex coacervation using proteins and polysaccharides enables efficient microencapsulation with high thermal stability, facilitating continuous core component release and yielding coacervates with superior properties for diverse applications. This study investigates the use of casein and pectin for microencapsulating Ocimum basilicum L. essential oil (EO) and phenolic extract (PE). Microencapsulation yield and efficiency were 85.3% and 89.8% for EO microcapsules (EO-MC) and 53.1% and 70.0% for PE microcapsules (PE-MC). Optical microscopy revealed spherical microcapsules; EO-MC had smooth surfaces, while PE-MC had porous surfaces. Thermal analysis showed stability, with both types exhibiting two stages of weight loss. XRD analysis indicated increased crystallinity in EO-MC and high crystallinity in PE-MC due to phenolic interactions. FTIR spectroscopy confirmed molecular interactions, including hydrogen bonding between phenolic compounds and the biopolymer matrix and amide bonds between the carboxyl groups of pectin and the amino groups of casein, ensuring the successful encapsulation of the bioactive compounds. These findings highlight the potential of casein and pectin for microencapsulating extracts, particularly EOs, for food industry applications. Full article

The accurate prediction and monitoring of rock drillability are essential for geomechanical modeling and optimizing drilling parameters. Traditional methods often rely on laboratory core experiments and well logging data to evaluate rock drillability. However, these methods can only obtain core samples and sonic logging data in drilled wells. To enable the real-time monitoring of bottom-hole rock drillability during drilling, we propose the following novel approach: data fusion and a CNN-GBDT framework for surface-based real-time monitoring. The specific process involves using 1D-CNN convolution to extract deep features from historical wells’ drilling data and sonic log data. These deep features are then fused with the original features and passed to the GBDT framework’s machine learning model for training. To validate the effectiveness of this method, this study conducted a case analysis on two wells in the Missan Oil Fields. CNN-GBDT models based on XGBoost, LightGBM, and CatBoost were established and compared with physical methods. The results indicate that the CNN-GBDT model centered on LightGBM achieved a mean square error (MSE) of 0.026, which was one-tenth of the MSE of 0.282 of the physical evaluation method. Furthermore, the effectiveness of the proposed CNN-GBDT framework for monitoring rock drillability suggests potential applications in monitoring other bottom-hole parameters. Full article

The lithofacies of a reservoir contain key information such as rock lithology, sedimentary structures, and mineral composition. Accurate prediction of shale reservoir lithofacies is crucial for identifying sweet spots for oil and gas development. However, obtaining shale lithofacies through core sampling during drilling is challenging, and the accuracy of traditional logging curve intersection methods is insufficient. To efficiently and accurately predict shale lithofacies, this study proposes a hybrid model called Stacking, which combines four classifiers: Random Forest, HistGradient Boosting, Extreme Gradient Boosting, and Categorical Boosting. The model employs the Grid Search Method to automatically search for optimal hyperparameters, using the four classifiers as base learners. The predictions from these base learners are then used as new features, and a Logistic Regression model serves as the final meta-classifier for prediction. A total of 3323 data points were collected from six wells to train and test the model, with the final performance evaluated on two blind wells that were not involved in the training process. The results indicate that the stacking model accurately predicts shale lithofacies, achieving an Accuracy, Recall, Precision, and F1 Score of 0.9587, 0.959, 0.9587, and 0.9587, respectively, on the training set. This achievement provides technical support for reservoir evaluation and sweet spot prediction in oil and gas exploration. Full article

The potential for oil and gas exploration within inter-salt reservoirs is substantial, primarily due to their significant heterogeneity, which complicates accurate predictions. This study focuses on the inter-salt reservoirs of the sixth sub-member of the fifth member of the Majiagou Formation (hereafter referred to as O₂m₅⁶) in the Ordos Basin, North China. Utilizing core samples, thin sections, and petrophysical data, we investigated the differential evolution and primary controlling factors of the inter-salt carbonate reservoirs. The key findings are as follows: (1) During the sedimentary phase of O₂m₅⁶, high-energy sediments, such as shoals and microbial mounds, were deposited in highlands, while low-energy sediments, including dolomitic lagoons and gypsiferous lagoons, emerged in depressions from west to east. (2) In a restricted–evaporative environment, highlands are prone to karstification, which significantly enhances the development of inter-salt reservoirs and generates a variety of reservoir spaces, including interparticle dissolved pores, growth-framework dissolved pores, and micropores between vadose silts. (3) The presence of alternating highlands and depressions obstructs seawater flow, leading to a progressive increase in salinity from west to east. This process ultimately facilitates the infilling of reservoir spaces with calcite, anhydrite, and halite cements in the same direction. (4) The three components—reservoir rocks, karstification, and infilling features—exert varying effects in the region and collectively govern the north–south distribution of inter-salt reservoirs. Overall, this study examines the characteristics and controlling factors of carbonate reservoirs within a restricted–evaporative platform environment and provides pertinent research cases for the exploration of inter-salt reservoirs. Full article