Search Results (59)

The mechanism of low- to middle-rank coal seam gas accumulation in the Baode block on the eastern edge of the Ordos Basin is well understood. However, exploration efforts in the Shizuishan area on the western edge started later, and the current understanding of enrichment and accumulation rules is unclear. It is important to systematically study enrichment and accumulation, which guide the precise exploration and development of coal seam gas resources in the western wing of the basin. The coal seam collected from the Shizuishan area of Ningxia was taken as the target. Based on drilling, logging, seismic, and CBM (coalbed methane) test data, geological conditions were studied, and factors and reservoir formation modes of CBM enrichment were summarized. The results are as follows. The principal coal-bearing seams in the study area are coal seams No. 2 and No. 3 of the Shanxi Formation and No. 5 and No. 6 of the Taiyuan Formation, with thicknesses exceeding 10 m in the southwest and generally stable thickness across the region, providing favorable conditions for CBM enrichment. Spatial variations in burial depth show stability in the east and south, but notable fluctuations are observed near fault F1 in the west and north. These burial depth patterns are closely linked to coal rank, which increases with depth. Although the southeastern region exhibits a lower coal rank than the northwest, its variation is minimal, reflecting a more uniform thermal evolution. Lithologically, the roof of coal seam No. 6 is mainly composed of dense sandstone in the central and southern areas, indicating a strong sealing capacity conducive to gas preservation. This study employs a system that fuses multi-source geological data for analysis, integrating multi-dimensional data such as drilling, logging, seismic, and CBM testing data. It systematically reveals the gas control mechanism of “tectonic–sedimentary–fluid” trinity coupling in low-gentle slope structural belts, providing a new research paradigm for coalbed methane exploration in complex structural areas. It creatively proposes a three-type CBM accumulation model that includes the following: ① a steep flank tectonic fault escape type (tectonics-dominated); ② an axial tectonic hydrodynamic sealing type (water–tectonics composite); and ③ a gentle flank lithology–hydrodynamic sealing type (lithology–water synergy). This classification system breaks through the traditional binary framework, systematically explaining the spatiotemporal matching relationships of the accumulated elements in different structural positions and establishing quantitative criteria for target area selection. It systematically reveals the key controlling roles of low-gentle slope structural belts and slope belts in coalbed methane enrichment, innovatively proposing a new gentle slope accumulation model defined as “slope control storage, low-structure gas reservoir”. These integrated results highlight the mutual control of structural, thermal, and lithological factors on CBM enrichment and provide critical guidance for future exploration in the Ningxia Autonomous Region. Full article

Ammonia is emerging as a promising zero-carbon marine fuel due to its high hydrogen density, low storage pressure, and long-term stability, making it well-suited for supporting sustainable maritime energy systems. However, its adoption introduces serious safety challenges, as its toxic, flammable, and corrosive properties pose greater risks than many other alternative fuels, necessitating rigorous risk assessment and safety management. This study presents a comprehensive investigation of potential ammonia leakage scenarios that may arise during the fuel gas supply process within confined compartments of marine vessels, such as the fuel preparation room and engine room. The simulations were conducted using FLACS-CFD V22.2, a validated computational fluid dynamics tool specialized for flammable gas dispersion and explosion risk analysis in complex geometries. The model enables detailed assessment of gas concentration evolution, toxic exposure zones, and overpressure development under various leakage conditions, providing valuable insights for emergency planning, ventilation design, and structural safety reinforcement in ammonia-fueled ship systems. Prolonged ammonia exposure is driven by three key factors: leakage occurring opposite the main ventilation flow, equipment layout obstructing airflow and causing gas accumulation, and delayed sensor response due to recirculating flow patterns. Simulation results revealed that within 1.675 s of ammonia leakage and ignition, critical impact zones capable of causing fatal injuries or severe structural damage were largely contained within a 10 m radius of the explosion source. However, lower overpressure zones extended much further, with slight damage reaching up to 14.51 m and minor injury risks encompassing the entire fuel preparation room, highlighting a wider threat to crew safety beyond the immediate blast zone. Overall, the study highlights the importance of targeted emergency planning and structural reinforcement to mitigate explosion risks in ammonia-fueled environments. Full article

The complex interaction of hydrothermal fluids and carbonate rocks is recognized to promote significant impacts on petroleum systems, reservoir porosity, and potential. The objective of this study is to investigate the fluid phases entrapped in the mineral phases of the Barra Velha Formation (Santos Basin), including their petrographic paragenetic relationships, relative timing, temperatures of migration events, and maximum temperature reached by the sedimentary section. The petrographic descriptions (387), Rock-Eval pyrolysis (107), fluid inclusion petrography (14), and microthermometry (428) were performed on core and sidewall samples from two wells from one field of the Santos Basin. Hydrocarbon source intervals were primarily identified in lithologies with high argillaceous content. Chert samples still retain some organic remnants indicative of their original composition prior to extensive silicification. Redeposited intraclastic rocks exhibit the lowest organic content and oil potential. A hydrothermal petroleum system is identified by fluids consisting in gas condensate, light to heavy undersaturated oil, occasionally accompanied by aqueous fluids influenced by juvenile and evaporitic sources, and localized flash vaporization events. These hydrothermal fluids promoted silicification and dolomitization, intense brecciation, and lead to enhanced porosity in different compartments of the reservoir. The relative ordering of paleo-hydrothermal oils and the main oil migration and accumulation events has improved our understanding of the petroleum systems in the basin. This contribution is significant for future regional research on the evolution of fluid systems and their implications for carbonate reservoirs. Full article

The widespread application of horizontal drilling technology has significantly enhanced the development efficiency of unconventional resources, particularly shale gas, by overcoming key technical challenges in reservoir exploitation. However, wellbore instability remains a critical challenge during shale gas horizontal drilling, as borehole wall collapse often results in the accumulation of large-sized cuttings (or blocky cuttings), increasing the risk of stuck pipe incidents. In this study, a large-scale circulating loop experimental system was developed to investigate the hydrodynamic behavior of blocky cuttings transport under the influence of multiple factors, including rate of penetration (ROP), well inclination, flow rate, drilling fluid rheology, and block size. The experimental results reveal that when ROP exceeds 15 m/h, the annular solid-phase concentration increases non-linearly. At a well inclination of 60°, the axial and radial components of gravitational force reach a dynamic equilibrium, resulting in the maximum cuttings bed height. To enhance cuttings transport efficiency and mitigate deposition, a minimum flow rate of 35 L/s and a drill pipe rotation speed of 90 rpm are required to maintain sufficient turbulence in the annulus. Drilling fluid plastic viscosity (PV) in the range of 65–75 mPa·s optimizes suspension efficiency while minimizing circulating pressure loss. Additionally, increasing fluid density enhances the transport efficiency of large blocky cuttings. A drill pipe rotation speed of 80 rpm is recommended to prevent the formation of sand-wave-like cuttings beds. These findings provide valuable hydrodynamic insights and practical guidelines for optimizing hole-cleaning strategies, ensuring safer and more efficient drilling operations in shale gas horizontal wells. Full article

The most common type of well in the Fuling shale gas field is the long horizontal section well. Once the energy attenuates, it is difficult to discharge the accumulated liquid. So, it is particularly important to determine the time of accumulation. Through indoor experiments, it was observed that droplets in the gas core flowing under critical conditions and the liquid film adhering to the tube wall cannot be ignored. It was also discovered that the liquid phase on the tube wall can form fluctuations due to the shear effect of the gas phase. Based on the observed distribution of gas–liquid phases in experiments, a critical liquid-carrying velocity calculation method considering the coexistence of droplets and liquid films, as well as the frictional resistance coefficient at the gas–liquid interface under wave morphology, was established. Integrating production data from 106 wells at home and abroad, as well as testing data from the Fuling example well, the new model was validated. The results showed that the new model can accurately diagnose fluid accumulation in different gas fields, with an accuracy rate of 86.8%, and it can provide an accurate diagnosis for fluid accumulation in gas wells in different water-producing gas fields. Full article

Under shut-in conditions in deepwater drilling, the gas invading the bottomhole ascends along the wellbore and accumulates at the wellhead, forming a high-pressure trap, challenging wellbore pressure prediction and control. The accurate prediction of bottomhole pressure is essential for well control during shut-in conditions. In this study, a new bottomhole pressure prediction model that considers wellbore storage effects was developed to address gas invasion issues during shut-in conditions in deepwater drilling. This model incorporates factors such as the wellbore elasticity, fluid compressibility, and drilling fluid filtration loss. The calculated values show good agreement with experimental values, with the average absolute and relative errors of 2.095 × 10⁻² MPa and 3.71%, respectively. Meanwhile, the results indicate that the bottomhole pressure initially increases logarithmically over time and then transitions to a linear increase, and the residual flow and gas ascent significantly influence the bottomhole pressure. Finally, the effects of various parameters on the bottomhole pressure were evaluated. Larger initial pressure differential, exposed thickness, and formation permeability accelerate the increase in bottomhole pressure during residual flow stage, while smaller filter cake permeability and drilling fluid viscosity quicken its increase during gas ascent stage. Drilling fluid density affects the initial pressure and the residual flow duration. The findings of this study would provide theoretical support for well control operations in deepwater drilling. Full article

The light oil wells within the Neogene Shawan Formation have been extensively drilled in the Chepaizi Uplift, reflecting an increase that provides new targets for unconventional resources in the Junggar Basin of northwestern China. However, the original sources of light oil remain controversial, as several source rocks could potentially generate the oil. For this study, we collected light oils and sandstone cores for biomarker detection using gas chromatography–mass spectrometry (GC-MS). Additionally, fluid inclusions were observed and described, and the homogenization temperatures of saltwater inclusions were measured to confirm the oil charging history in conjunction with well burial and thermal history analysis. Based on these geochemical characteristics and carbon isotopic analysis, the results indicate that light oil in the Chepaizi Uplift zone primarily originates from Jurassic hydrocarbon source rocks in the Sikeshu depression, with some contribution from Cretaceous hydrocarbon source rocks. Jurassic hydrocarbon source rocks reached a peak of hydrocarbon generation in the middle to late Neogene. The resulting crude oil predominantly migrated along unconformities or faults to accumulate at the bottom of the Cretaceous or Tertiary Shawan Formation, forming anticlinal or lithologic oil reservoirs. Some oil reservoirs contain mixtures of Cretaceous immature crude oil. During the Neogene light oil accumulation process, the burial rate of reservoirs was high, and the efficiency of charging and hydrocarbon supply was relatively high as well. Minimal loss occurred during the migration of light oil, which significantly contributed to its rapid accumulation. Full article

The Middle Permian Maokou Formation carbonate rocks in the southern Sichuan Basin are import targets for hydrocarbon exploration, with numerous gas fields discovered in structural traps. However, as exploration extends into slope and syncline zones, the limestone reservoirs become denser, and fluid distribution becomes increasingly complex, limiting efficient exploration and development. Identifying the key factors controlling natural gas accumulation is therefore critical. This study is the first to apply deep learning techniques to fault detection in the southern Sichuan Basin, identifying previously undetected WE-trending subtle strike-slip faults (vertical displacement < 20 m). By integrating well logging, seismic, and production data, we highlight the primary factors influencing natural gas accumulation in the Maokou Formation. The results demonstrate that 80% of production comes from less than 30% of the well, and that high-yield wells are strongly associated with faults, particularly in slope and syncline zones where such wells are located within 200 m of fault zones. The faults can increase the drilling leakage of the Maokou wells by (7–10) times, raise the reservoir thickness to 30 m, and more than double the production. Furthermore, 73% of high-yield wells are concentrated in areas of fault intersection with high vertical continuity. Based on these insights, we propose four hydrocarbon enrichment models for anticline and syncline zones. Key factors controlling gas accumulation and high production include fault intersections, high vertical fault continuity, and local structural highs. This research demonstrates the effectiveness of deep learning for fault detection in complex geological settings and enhances our understanding of fault systems and carbonate gas reservoir exploration. Full article

The Kuqa Foreland Basin is an important hydrocarbon-producing basin in western China. The Dabei area is an important zone for hydrocarbon accumulation. High fluid overpressures in the Lower Cretaceous Bashijiqike Formation are related to multi-genetic processes. However, the formation and evolution of pressure remain unclear, hindering the further development of oil and gas migration and accumulation. In this study, the overpressure distribution is described based on a drill stem test and mud density data. The formation and quantification of multi-genetic overpressure were evaluated based on well-logging data and basin simulation technology (Ansys Workbench). The coupling evolution of multi-genetic overpressure was examined based on the basin simulation technique. Finally, the influence of overpressure on hydrocarbon accumulation was explored. The results showed that the residual pressure of the Bashijiqike Formation in the Dabei area ranged from 40 to 60 MPa. The main causes of pressure in the Bashijiqike Formation in the Dabei area were disequilibrium compaction overpressure (2–6 MPa, contribution of 8–15%), tectonic compression overpressure (10 MPa, contribution of 30%), and fracture transfer overpressure (15–20 MPa, contribution of 8–15%). With respect to the evolution process of multiple pressures in the Bashijiqike Formation in the Dabei region, at 0–23.3 Ma, the overpressure due to disequilibrium compaction was <10 MPa and increased slowly to 18 MPa at 2.48–23.3 Ma. At 2.48 Ma, the tectonic compression was enhanced, and the residual pressure reached ~50 MPa. At 1.75–2.48 Ma, fracture activity was enhanced, leading to the generation of fracture transfer overpressure. Under these conditions, the residual pressure exceeded 60 MPa. Finally, the Bashijiqike Formation in the Dabei area is a favorable area for vertical and lateral migration of oil and gas. This study is of great significance to the formation and evolution of multi-origin overpressure in the same basin type and its influence on oil and gas accumulation. Full article

A major problem in natural gas production is the waterlogging of gas wells. This problem occurs at the end of a well’s life when the reservoir pressure becomes low and the gas velocity in the well tubing is no longer sufficient to bring the gas-related fluids (water and gas condensate) up to the surface. This causes water to accumulate at the bottom of the gas well, which can seriously reduce or even stop gas production altogether. This paper presents a study of the foaming of reservoir water using foaming sticks with the trade names BioLight 30/380, BioCond 30, BioFoam 30, BioAcid 30/380, and BioCond Plus 30/380. The reservoir waters tested came from near-well separators located at three selected wells that had undergone waterlogging and experienced a decline in natural gas production. They were characterised by varying physical and chemical parameters, especially in terms of mineralisation and oil contaminant content. Laboratory studies on the effect of foaming agents on the effectiveness of foaming and lifting of reservoir water from the well were carried out on a laboratory bench, simulating a natural gas-producing column using surfactant doses in the range of 1.5–5.0 g/m³ and measuring the surface tension of the water, the volume of foam generated as a function of time and the foamed reservoir water. The performance criterion for the choice of surfactant for the test water was its effective lifting in a foam structure from an installation, simulating a waterlogged gas well and minimising the dose of foaming agent introduced into the water. The results obtained from the laboratory tests allowed the selection of effective surfactants in the context of foaming and uplift of reservoir water from wells, where a decline in natural gas production was observed as a result of their waterlogging. In the next stage, well tests were carried out based on laboratory studies to verify their effectiveness under conditions typical for the production site. Tests carried out at natural gas wells showed that the removal of water from the bottom of the well resulted in an increase in natural gas production, ranging from 56.3% to 79.6%. In practice, linking the results of laboratory tests for the type and dosage of foaming agents to the properties of reservoir water and gas production parameters made it possible to identify the types of surfactants and their dosages that improve the production of a given type of natural gas reservoir in an effective manner, resulting in an increase in the degree of depletion of hydrocarbon deposits. Full article

The process of coal measure gas accumulation is relatively complex, involving multiple physicochemical processes such as migration, adsorption, desorption, and seepage of multiphase fluids (e.g., methane and water) in coal measure strata. This process is constrained by multiple factors, including geological structure, reservoir physical properties, fluid pressure, and temperature. This study used Well Z-7 in the Qinshui Basin as the research object as well as numerical simulations to reveal the processes of methane generation, migration, accumulation, and dissipation in the geological history. The results indicate that the gas content of the reservoir was basically zero in the early stage (before 25 Ma), and the gas content peaks all appeared after the peak of hydrocarbon generation (after 208 Ma). During the peak gas generation stage, the gas content increased sharply in the early stages. In the later stage, because of the pressurization of the hydrocarbon generation, the caprock broke through and was lost, and the gas content decreased in a zigzag manner. The reservoirs in the middle and upper parts of the coal measure were easily charged, which was consistent with the upward trend of diffusion and dissipation and had a certain relationship with the cumulative breakout and seepage dissipation. The gas contents of coal, shale, and tight sandstone reservoirs were positively correlated with the mature hydrocarbon generation of organic matter in coal seams, with the differences between different reservoirs gradually narrowing over time. Full article

The extraction of shale gas via horizontal drilling presents considerable challenges, primarily due to the accumulation of cuttings within the annular space, resulting in increased friction, torque, and potential drilling complications. To address this issue, the study proposes an experimental setup aimed at simulating cuttings transport under various operational conditions, with a particular emphasis on gas wells. The methodology encompasses the modulation of the drilling fluid flow rate and the drill’s rotational speed to examine the transport velocity of cuttings. Furthermore, the study analyzes the impact of annular eccentricity on return volume, transport time, and cuttings bed height. Critical initiation velocities for cuttings across different motion modes were also determined, and theoretical calculations were compared with empirical data. The findings indicate that an increased flow rate of drilling fluid and higher rotation speed substantially improve the transport of cuttings, thereby minimizing bed formation, whereas increased eccentricity hinders this process. The results revealed that the theoretical model showed a greater overestimation of the start-up velocity for spherical particles, with average errors ranging from 15.50% to 17.56%. In contrast, the model exhibited better accuracy for non-spherical (flaky) particles, with errors between 8.63% and 9.61%. Under non-rotating conditions, the average error of the model was approximately 8.32%, while the introduction of drill tool rotation increased the average error to 11.94%. These results have the potential to optimize operational parameters in shale gas well drilling and may contribute to the development of specialized borehole purification tools. Full article

Drill-bit metamorphism (DBM) is the process of thermal degradation of drilling fluid at the interface of the bit and rock due to the overheating of the bit. The heat generated by the drill when drilling into a rock formation promotes the generation of artificial hydrocarbon and non-hydrocarbon gas, changing the composition of the gas. The objective of this work is to recognize and evaluate artificial gases originating from DBM in wells targeting oil accumulations in pre-salt carbonates in the Santos Basin, Brazil. For the evaluation, chromatographic data from advanced mud gas equipment, drilling parameters, drill type, and lithology were used. The molar concentrations of gases and gas ratios (especially ethene/ethene+ethane and dryness) were analyzed, which identified the occurrence of DBM. DBM is most severe when wells penetrate igneous and carbonate rocks with diamond-impregnated drill bits. The rate of penetration, weight on bit, and rotation per minute were evaluated together with gas data but did not present good correlations to assist in identifying DBM. The depth intervals over which artificial gases formed during DBM are recognized should not be used to infer pay zones or predict the composition and properties of reservoir fluids because the gas composition is completely changed. Full article

The prediction of the liquid build-up height in gas wells is a crucial aspect of reservoir development and is essential for the efficient execution of drainage and gas extraction operations. Excessive liquid accumulation can lead to well flooding and operational shutdowns, resulting in significant economic losses. To prevent such occurrences, accurate estimation of the liquid height in gas well tubing is necessary. However, existing petroleum engineering models face numerous challenges in predicting liquid height, including complex theoretical solution steps and reliance on fundamental well parameters and extensive empirical data. The paper proposes an innovative blend of the Crayfish Optimization Algorithm (COA) with the eXtreme Gradient Boosting (XGBoost) methodology to forecast the liquid loading heights in gas wells. The COA is employed to optimize eight hyperparameters of the XGBoost, including the number of trees, maximum depth, minimum child weight, learning rate, minimum loss reduction, subsample, L1 regularization, and L2 regularization. After fine-tuning the hyperparameters, the XGBoost undergoes a retraining process, followed by an evaluation. Through comparative analysis with actual measurements from 32 wells in a gas field as well as support vector regression (SVR), XGBoost, random forest (RF), and PLATA (which predict liquid volume in the tubing and annulus), the proposed COA–XGBoost demonstrates a high degree of alignment with the measured values. It provides the most accurate predictions, with a mean relative error of only 2.25%. Compared with the traditional XGBoost, the COA–XGBoost reduced the mean relative error in predicting gas well tubing liquid loading height by 32.63%. Compared with the previous PLATA, the proposed model achieved a 3.52% decrease in mean relative error, enabling more accurate assessment of the severity of liquid loading in gas wells. Full article

Usually, deep oil and gas accumulation is often controlled by strike–slip faults. However, in the Tarim Basin, deep Ordovician oil and gas accumulations are also found in areas far from the fault zone. The process of oil and gas accumulation in deep reservoirs far from strike–slip fault zones is still unclear at present. The source and evolution of Ordovician fluids were analyzed using inclusion geochemical methods and the U–Pb dating technique. The analysis of rare earth elements and carbon–oxygen–strontium isotopes in the reservoirs showed that the reservoirs were weakly modified by diagenetic fluid. The fluid was derived from the fluid formation during the same period as the seawater, and no oxidizing fluid invaded the reservoir. The late oil and gas reservoirs had good sealing properties. The U–Pb dating results combined with homogenization temperature data revealed that the first-stage oil was charged during the Late Caledonian Period, and the second-stage natural gas was charged during the Middle Yanshanian Period. The evolution of the paleo-pressure showed that the charging of natural gas in the Middle Yanshanian was the main reason for the formation of reservoir overpressure. The strike–slip fault zone was basically inactive in the Middle Yanshanian. During this period, the charged natural gas mainly migrated to the reservoir along the unconformity surface and the open strike–slip fault zone in the upper part of the Ordovician reservoir. The source of the fluid shows that the reservoir in the late stage had good sealing properties, and there was no intrusion of exogenous fluid. The overpressure in the reservoir is well preserved at present. Full article