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In this work, an integrated system for hydrogen energy utilization system (HUS) in oil and gas fields was constructed focusing on two scenarios: hydrogen fuel cell bus and industrial combustion. The energy consumption, environmental, economic, and energy efficiency were assessed for the various HUS technological pathways associated with produced water treatment, hydrogen production, transport and storage, refueling, and utilization. The entropy weight-TOPSIS method was utilized to assess the optimal pathway. The results indicate that the pathway of alkaline water electrolysis for hydrogen production and pipeline transportation to gas-hydrogen refueling stations for hydrogen fuel cell bus shows excellent comprehensive indicators, which has an energy consumption of 197.15 MJ/kgH 2 , the levelized cost of hydrogen (LCOH) of 6.70 USD/kgH 2 , a system energy efficiency of 30.43%. For industrial combustion, the best pathway is alkaline water electrolysis for hydrogen production and pure H 2 pipeline transportation. Sensitivity analyses were conducted to explore the impact of different factors on LCOH. As the electricity price decreases to 0.014 USD/kWh, LCOH will reduce by 2.50 USD/kgH 2. The reduction in electricity prices will further increase the feasibility of hydrogen energy in the future. • The Hydrogen utilization system (HUS) in oil and gas fields was proposed. • The technical-economic and environmental performance of HUS were analyzed. • The entropy-weighted TOPSIS method is used to select the optimal pathway. • Alkaline water electrolysis and pipeline transportation are the best pathways. • Electricity prices are the most sensitive factor to LCOH. [ABSTRACT FROM AUTHOR]

Lithology identification assumes an absolutely crucial role in the realm of reservoir delineation, functioning as a fundamental prerequisite for accurately determining porosity, oil saturation, and sundry other parameters. The precise identification of lithology effectively forms a foundation for ensuring the effective exploration and development of oil and gas fields in the subsequent stages. Traditional logging lithology identification methods have many limitations, and therefore many challenges. Therefore rapid and accurate lithology identification is a matter of significant concern and importance. This study identified the initial lithology using a cross-plot approach, capitalizing on the distinctive characteristics of the lithology logging response. Subsequently, a rapid lithology identification method was developed for marine carbonate rocks by integrating artificial neural networks and the logging curves. To evaluate its accuracy and precision, the outcomes were compared with the core data and the lithology scanning logging techniques. The neural network–based method proposed in this paper can enable swift and accurate identification of lithologies, encompassing even transitional lithologies such as silty limestone and limy dolomite. Therefore, it provides novel theoretical and technical support that is of tremendous significance for subsequent research and applications. [ABSTRACT FROM AUTHOR]

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

The development of infill wells have gained significant traction in enhancing shale gas recovery in the Sichuan Basin. During the development of infill wells, the production of the parent wells leads to changes in in-situ stress, which in turn affects the fracture morphology of the infill well, resulting in frac-hits. These frac-hits are commonly considered a potential hazard to the adjacent infill well production and wellbore. In this study, a comprehensive flow-geomechanics coupling model has been developed to address this challenge. The model incorporates the processes of parent well fracturing and production, evolution of in-situ stress after production, and infill well fracturing and production. This study discusses four cases in the Sichuan Basin, each highlighting intriguing field phenomena. The first case focuses on an infill well situated in the same layer, while the second case pertains to a three-layers infill wells pad. The third case delves into the phenomenon of frac-hits in deep shale gas reservoirs (3800 m), while the final case explores the effect of high-steep structures in the fracturing process. By utilizing this integrated model and field data, the mechanisms underlying these phenomena are observed. The results indicate that: (i) The 'microseismic events barrier' (MSEB) effect caused by stress shadow has been reported and the main reasons have been analyzed. (ii) The range of stress shadow is critical to the deployment of multi-layers infill well pattern, the influence range in both horizontal and vertical directions is related to the size of hydraulic fractures. (iii) In deep shale gas reservoir, high stress and the development of natural fracture zones are the main reasons of frac-hit and the fracturing sequence can exacerbate this phenomenon. (iv) The high formation dip in the high-steep structural zone will restrict the propagation of hydraulic fractures in the horizontal direction. Through this research, valuable insights into the behavior of infill wells in the Sichuan Basin have been obtained, shedding light on the challenges and opportunities associated with maximizing shale gas recovery in this region. Highlights: In this study, a comprehensive flow-geomechanics coupling model has been developed to address the stress evolution caused by the depletion of parent well and then hydraulic fracturing of infill wells can be simulated based on the updated stress. Based on this method, we have conducted a large number of infill well case studies on shale gas fields across Sichuan Basin. The four case studies reported in this paper belong to different shale gas fields and have their own highlights and uniqueness. The 'microseismic events barrier' effect (MSEB effect) was reported in the first case which explained the reason for the sharp decrease in the number of microseismic (MS) events when the MS were close to the boundary of the parent well. Besides the phenomenon of parent well pressure regained through the enhanced permeable channel. The second case pertains to a three-layers infill wells pad which the infill wells were drilled both in upper, middle, and bottom layers. The stress influenced range in both horizontal and vertical directions analyzed. The third case delves into the inter-well interference in deep shale gas reservoirs. For the severe frac-hits having a negative effect on production and stimulation treatment, the influencing factors and types of frac-hits were summarized. The final case explores the effect of high-steep structures on the fracture propagation and explains why the hydraulic fracturing treatment in this area did not meet expectations [ABSTRACT FROM AUTHOR]

With the increase in production of sour oil and gas fields, mitigation of production-related failures due to H2S corrosion of mild steel is a key challenge. In H2S environments, most failures occur due to localized corrosion originating from the galvanic coupling between mild steel and conductive iron sulfide corrosion products. However, the mechanism of the galvanic coupling between mild steel and iron sulfides and the effect of influential parameters, have not been studied yet. Here, we provide a systematic experimental investigation on the galvanic corrosion between mild steel and iron sulfides by examining the effect of the critical factors: iron sulfide type, cathode to anode surface area ratio, and salt concentration. Specifically, we focus on pyrite and pyrrhotite as the main corrosion products found in localized corrosion of mild steel in H2S environments. Our results show that the cathodic current obtained on pyrrhotite was an order of magnitude higher than that obtained on pyrite, leading to a higher galvanic current for coupled mild steel-pyrrhotite compared to coupled mild steel-pyrite. Moreover, our study reveals that the increase of cathode to anode surface area ratio and, to some extent, the increase of salt concentration, enhance the galvanic current for the coupled materials. [ABSTRACT FROM AUTHOR]

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

The application of classic foaming agent faces several issues, including excessive use of defoaming agent, inadequate defoaming, pipeline blockage due to silicone oil precipitation, and high development cost of the foaming agent. To address the aforementioned issues, a novel intelligent foaming agent was created. This resulted in the development of a new intelligent foaming and discharging agent system. The study focused on analyzing key performance indicators of the foaming agent system, including temperature resistance, salt resistance, oil resistance, phase transition temperature point, foaming ability, foam half-life, liquid carrying capacity, and self-defoaming ability. The experimental findings indicate that TS-1 and ESAB exhibit favorable foaming performance and stability under the conditions of 90 °C temperature, 20 × 104 mg/L salinity, and 40% condensate oil content after a 1:1 mixture. Additionally, they are capable of undergoing phase transition within the temperature range of 12 to 15.2 °C. The Waring blender stirring method resulted in the foaming agent solution, which had a concentration of 3 g/L, reaching a volume of 487 mL. The foam's half-life was 20 min, and the liquid carrying rate was 91.7%. After a duration of 20 min, the rate of self-defoaming was 81.6%. The addition of the self-developed synergist facilitated the defoaming process, which was successfully accomplished within a time frame of 10 min. Moreover, the self-defoaming rate achieved a remarkable 100%. The foam drainage agent system may autonomously react to variations in ambient temperature and achieve phase transition behavior through temperature stimulation. This is accomplished by utilizing the natural temperature difference between the bottom hole and the wellhead during foam drainage gas recovery operations. This innovation presents a novel concept for the foam drainage agent used in recovering drainage gas. It simplifies the operation of gas recovery in oil and gas wells, provides solutions for further smartening up oil and gas fields. It holds immense theoretical and practical importance. [ABSTRACT FROM AUTHOR]

The continuous discovery of giant oil and gas fields in deep-water low stand fans has made deep-water submarine fan reservoirs with huge oil and gas potential important targets for oil and gas exploration and development. Nowadays, machine learning algorithm has been proven to be an effective method to classify various rock types from geophysical logging data, but rarely has there been focus on predicting deep-water submarine fans in previous studies. In this paper, we utilized five classical Boosting machine learning algorithms, namely GBDT, XGBoost, LightGBM, CatBoost, and LogitBoost, to identify 14 deep-water submarine fan lithofacies types from 7 wells in a West African oilfield. To address the sample non-balance problem, we employed SMOTE and MAHAKIL oversampling techniques and optimized the hyperparameters of the model using Genetic Algorithm. The experimental results show that the model performance is improved by using oversampling technologies and hyperparameter optimization. The proposed MAHAKIL-GA-GBDT algorithm is the most effective in identifying the lithofacies of deep-water submarine fans, with an accuracy of 0.986. This study provides a new approach for identifying deep-water submarine fan lithofacies and highlights the potential of machine learning algorithms in this field. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

As a common method for liquid drainage in wave‐shaped pipelines, foam drainage has been used in gas‐gathering pipelines in various oil and gas fields. One of the common problems encountered in wave‐shaped foam drainage pipelines is the inaccurate prediction of the liquid retention rate. This issue makes it difficult to predict liquid accumulation points, which affects gas output efficiency, causes pipeline corrosion, and generates natural gas hydrates. To clarify the liquid‐holding rate law of wavy foam drainage pipelines is studied. In this study, through experiments to verify the accuracy of the numerical simulation method, we investigate the easiest liquid accumulation points and the liquid‐holding rate of wave‐shaped foam drainage pipelines, with factors such as inlet gas velocity, inlet liquid velocity, import and export differential pressure, undulation angle, and inlet temperature change rule. Among them, the error between the numerical simulation results and the experimental results is 4.68%. Finally, after considering the influence of the aforementioned factors on the liquid retention rate of wave‐shaped pipelines, a new liquid retention rate calculation model for wave‐shaped pipelines with foam drainage is established by introducing dimensionless numbers, such as gas‐phase velocity coefficient, liquid‐phase velocity coefficient, and angle correction coefficient. The method is compared with the results of previous research, and the error is within 15%. The model has a simple form and high calculation accuracy, providing a theoretical basis for pipeline inspectors to predict liquid accumulation conditions and reasonably adjust production schedules. [ABSTRACT FROM AUTHOR]

The tight reservoirs in the Sichuan Basin generally contain water and have complex gas–water relationships. The dynamic changes and main controlling factors of natural gas injection are unclear, which has had a serious impact on the exploration and development of tight sandstone gas. This article selects samples from Yongqian and Qiulin gas fields to characterize the reservoir characteristics of the tight sandstone samples in the Xu-3 section. Nuclear magnetic resonance technology is applied to plan gas–water injection simulation experiments, and the dynamic changes in pore water and gas content during the natural gas injection of tight reservoir rock samples are characterized. The main controlling factors are analyzed based on the theory of nuclear magnetic resonance singlet and multifractal models. The results showed that material composition, pore type, structural characteristics, and physical properties cooperatively control the charging characteristics of natural gas. There was no significant difference in mineral content among the tight sandstone samples, and the pore morphology types were mainly parallel plate-like pores and fracture-type pores. There were significant differences in the pore structure characteristics of the samples with varying burial depths. The heterogeneity of gas-bearing pores is negatively related to the buried depth of tight sandstone, is a coupling relationship with quartz and feldspar content, and is negatively correlated with pore permeability. The stronger the sample heterogeneity, the more unfavorable it is for natural gas migration and accumulation. [ABSTRACT FROM AUTHOR]

Methane (CH4) is the second-largest greenhouse gas contributing to global climate warming. As of 2022, methane emissions from the oil and gas industry amounted to 3.586 million tons, representing 13.24% of total methane emissions and ranking second among all methane emission sources. To effectively control methane emissions in oilfield regions, this study proposes a multi-source remote sensing data fusion method based on the concept of data fusion, targeting high-emission areas such as oil and gas fields. The aim is to construct an XCH4 remote sensing dataset that meets the requirements for high resolution, wide coverage, and high accuracy. Initially, XCH4 data products from the GOSAT satellite and the TROPOMI sensor are matched both spatially and temporally. Subsequently, variables such as longitude, latitude, aerosol optical depth, surface albedo, digital elevation model (DEM), and month are incorporated. Using a local random forest (LRF) model for fusion, the resulting product combines the high accuracy of GOSAT data with the wide coverage of TROPOMI data. On this basis, ΔXCH4 is derived using GF-5. Combined with the GFEI prior emission inventory, the high-precision fusion dataset output by the LRF model is redistributed grid by grid in oilfield areas, producing a 1 km resolution XCH4 grid product, thereby constructing a high-precision, high-resolution dataset for oilfield regions. Finally, the challenges that emerged from the study were discussed and summarized, and it was envisioned that, in the future, with the advancement of satellite technology and algorithms, it would be possible to obtain more accurate and high-resolution datasets of methane concentration and apply such datasets to a wide range of fields, with the expectation that significant contributions could be made to reducing methane emissions and combating climate change. [ABSTRACT FROM AUTHOR]

Automated and/or autonomous offshore platforms or units are becoming more important in the energy sector, whether they are being used for oil and gas extraction or for carbon storage purposes. Automation means that harsh working conditions and risks of personal injury to crew could be cut to virtually zero. Automation also provides significant cost savings and helps make less attractive oil and gas fields more economically viable to exploit. However, automation does come with its own set of challenges—the notable one being the cybersecurity threat. Any regulation or international standard dealing with the cybersecurity risk which is relevant to automated offshore units is usually framed within those rules that apply to ships. This article examines to what extent that regulatory approach, especially that of the International Maritime Organisation's (IMO) regime, could and should apply to automated or autonomous offshore platforms. It argues that whilst, for now, the IMO cybersecurity guidelines are relevant, a more targeted regulatory approach is needed. [ABSTRACT FROM AUTHOR]

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

A carbamate surfactant was synthesized using octadecanol polyoxyethylene ether(AEO) and isocyanatoethyl methacrylate(IEM) as functional monomers. Subsequently, active-carbamate-surfactant-modified PER nanomicrospheres were prepared through two-phase aqueous dispersion polymerization, utilizing acrylamide (AM), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and ethylene glycol dimethacrylate (EGDMA) as raw materials. The microstructures and properties of the nanomicrospheres were characterized and examined using infrared spectroscopy, nanolaser particle size analysis, thermogravimetric analysis, scanning electron microscopy, rheometry, rotating drop ultra-low interfacial tensiometry, and core-driven experiments. The results revealed that the synthesized PER nanomicrospheres exhibit a uniform particle size distribution, with an average particle size of 336 nm. Furthermore, the nanomicrospheres exhibit a thermal decomposition temperature of 278℃, demonstrating good thermal stability. The nanomicrospheres also exhibit favorable expansion and viscoelastic properties. Upon the injection of 3wt.% of the PER nanomicrospheres into a non-homogeneous core, the blocking rate (η) reaches 90.32%, while the recovery rate increases by 30.2%. This improvement is attributed to the unique structural design of the nanomicrospheres, allowing them to form a thin film at the three-phase oil–water-rock interface and promoting oil emulsification and stripping. Overall, the PER nanomicrospheres effectively control fluid dynamics within reservoirs, mitigate the loss of oil and gas resources, enhance the economic benefits of oil and gas fields, and thus demonstrate good application prospects. [ABSTRACT FROM AUTHOR]

Verifying the pattern of toxic gas dispersion simulations under mountainous conditions is vital for emergency response and rescue. In this study, a comparative analysis is conducted between CALPUFF (California Puff Model) and CFD (Computational Fluid Dynamics) gas dispersion modeling focusing on the range of Semi-Lethal Concentration (LC50) and Immediate Danger to Life and Health Concentration (IDLH). To identify general dispersion patterns, a hypothetical pipeline breakout accident in a mountainous area is simulated and thirteen groups of simulation conditions are set up for the experiments, including calm wind (velocity less than 0.5 m/s) and winds from the east (E), south (S), west (W), and north (N) at velocities of 1, 2, and 3 m/s with a 1 arc-second degree SRTM data as terrain data. Comparative experiments show the diffusion patterns of the two models are essentially consistent, and the overall dispersion range deviation between two methods is within 266 m. The evaluation of CALPUFF's adaptability for microscale mountainous environments indicates its potential use for high-sulfur gas fields and gas dispersion simulations in emergency scenarios. [ABSTRACT FROM AUTHOR]

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

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

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

Investigating the primary influencing factors that regulate the enrichment of shallow gas not only deepens our understanding of the rules governing shallow gas enrichment in deep-ocean environments but also has the potential to enhance the success rate of locating shallow gas reservoirs. Recent drilling activities in the LS36 gas field located in the central Qiongdongnan Basin have revealed a substantial shallow gas reserve within the sediments of the Quaternary Ledong Formation, marking it as the first shallow gas reservoir discovered in the offshore region of China with confirmed natural gas geological reserves surpassing 100 billion cubic meters. However, the formation mechanism and influencing factors of shallow gas enrichment remain elusive due to the limited availability of 3D seismic and well data. This study employs seismic interpretation and digital simulation to decipher the dynamics of shallow gas accumulation and utilizes the carbon isotope composition of methane to ascertain the origin of the shallow gas. Our results show that the shallow gas is primarily concentrated within a large-scale submarine fan, covering a distribution region of up to 2800 km2, situated in the deep-sea plain. The δ13 C1 methane carbon isotope data ranges from −69.7‰ to −45.2‰ and all δ13 C2 values are above −28‰, suggesting that the shallow gas within the Ledong Formation is derived from a mix of biogenic gas produced in shallow strata and thermogenic gas generated in deeper source rocks. The results of gas sources, seismic profiles, and digital simulations suggest that thermogenic gas originating from the Lingshui and Beijiao sags was transported to the Quaternary submarine fan via a complex system that includes faults, gas chimneys, and channel sands. The mass-transported deposits (MTDs) in the upper reaches of the submarine fan have effectively acted as a seal, preventing the escape of shallow gas from the fan. Therefore, the factors contributing to the enrichment of shallow gas in the Qiongdongnan Basin include the presence of favorable submarine fan reservoirs, the availability of two distinct gas sources, the effective sealing of MTDs, and the presence of two efficient transport pathways. A conceptual model for the accumulation of shallow gas is developed, illuminating the complex formation–migration–accumulation process. This study underscores the importance of aligning multiple influencing factors in the process of shallow gas accumulation, and the suggested accumulation model may be pertinent to shallow gas exploration in other marginal sea basins. [ABSTRACT FROM AUTHOR]

The research on deepwater oil and gas exploration areas is relatively limited, and sample collection is difficult. A drilled coal sample from Yanan Depression was used to investigate the hydrocarbon generation process, and the potential, by a gold tube thermal simulation experiment. The results show that the total gas yield was much higher than the oil yield. According to an analysis of the gas pyrolysis data, as represented by ln(C1/C2) and ln(C2/C3), the gas generation process consisted of two forms, namely, primary gas with ~1.33% Ro and secondary gas that occurred at levels greater than 1.33% Ro. The primary gas from kerogen was generated at ~1.33% Ro, which coincided with the %Ro value of the maximum oil yield. The activation energy distribution of the C1–C5 generation processes ranged from 54 to 72 kcal/mol, with a frequency factor of 6.686 × 1014 s−1 for the coal sample. We constructed the history of gas generation on the basis of the process and kinetic parameters, combined with data on the sedimentary burial and thermal history. The extrapolation of the gas history revealed that the gas has been generated from 5 Ma to the present, with a maximum yield of 178.5 mg/gTOC. This history suggests that the coal has good primary gas generation potential and provides favorable gas source conditions for the formation of gas fields. This study provides a favorable basis for expanding the effective source rock areas. [ABSTRACT FROM AUTHOR]

Oil and gas fields represent the backbone of industries. Such industries are exposed to many physical risks, such as sabotage and oil and gas leaks, theft of equipment, and technological hazards (e.g., exposure to hacking of security and sensitive information by attackers). In this regard, a variety of decentralized studies still suffer from storage limitations, long response times, high costs, and redundant or unnecessary data storage due to false positive transmission, as well as 51%, Sybil, Sniffing, Eavesdropping, Spoofing, Phishing, and Social engineering attacks. Our paper proposes the utilization of surveillance thermal CCTV cameras based on Hyberledger Fabric blockchain to enhance safety and security in oil and gas fields. The proposed scheme incorporates fog nodes to facilitate the authentication process and reduce the time response. Our system also adopts InterPlanetary File System (IPFS) storage that enables scalability and provides hash-based integrity to stored data. Moreover, IPFS integrates with cuckoo filters to reduce superfluous or unneeded data. Our work offers low-complexity authentication utilizing ECDSA, balancing high security and complexity, and resisting well-known malicious and cyberattacks. Furthermore, the proposed scheme has been verified its validation by proving its resistance to attacks. Compared with related literature that used the blockchain or fog computing technology, the performance analysis accomplished the lowest cost results (52,000736 ms) in the computation cost and (800 bits for each user, and CCTV) in the communication cost. It is worth noting that we relied on reliable sources to calculate these results. [ABSTRACT FROM AUTHOR]

Mussel‐inspired materials have been widely studied due to their excellent adhesion and self‐healing properties, but few studies have introduced this interesting property into the fracturing development of deep/ultra‐deep oil and gas fields. Herein, a new type of mussel‐inspired delayed crosslinking gel fracturing fluid is reported, which is formed by mussel‐inspired polymers containing many catechol groups and organic zirconium delayed crosslinkers. The strong supramolecular interaction in mussel‐inspired polymers can construct a more complex and stable dually cross‐linked polymer network based on conventional chemical crosslinking, to cope with harsh conditions such as high temperature and shear in reservoirs. After shearing at 200 °C, the reserved viscosity of mussel‐inspired delayed crosslinking gel is as high as 95 mPa·s. More importantly, the viscosity of gel remains basically unchanged at 25 °C, and the cross‐linking is completed within 300 s at 90 °C. The chemical force probe atomic force microscope (AFM) technology has successfully demonstrated that catechol groups are the main source of supramolecular interaction in mussel‐inspired polymers. The molecular simulation results show that due to the addition of catechol groups, the hydrogen bond interactions within the mussel‐inspired polymers molecules are enhanced. And the additional hydrogen bonds formed are more stable at high temperature. [ABSTRACT FROM AUTHOR]

A comprehensive digital transformation has been undergone by the oil and gas industry, wherein digital twins are leveraged to enable real-time data analysis, providing predictive and diagnostic engineering insights. The potential for developing intelligent oil and gas fields is substantial with the implementation of digital twins. A digital twin framework for gear rack drilling rigs is proposed, built upon an understanding of the digital twin composition and characteristics of the gear rack drilling rig lifting system. The framework encompasses descriptions of digital twin characteristics specific to drilling rigs, the application environment, and behavioral rules. The modeling approach integrates mechanism modeling, real-time performance response, instantaneous data transmission, and data visualization. To illustrate this framework, exemplary case studies involving the transmission unit and support unit of the lifting system are presented. Mechanism models are constructed to analyze dynamic gear performance and support unit response. Real-time data transmission is facilitated through sensor-based monitoring, enhancing the prediction speed and accuracy of dynamic performance through a synergy of mechanism modeling, machine learning, and real-time data analysis. The digital twin of the lifting system is visualized utilizing the Unity3D platform. Furthermore, functionalities on data acquisition, processing, and visualization across diverse application scenarios are encapsulated into modular components, streamlining the creation of high-fidelity digital twins. The frameworks and modeling methodologies presented herein can serve as a foundational and methodological guide for the exploration and implementation of digital twin technology within the oil and gas industry, ultimately fostering its advancement in this sector. [ABSTRACT FROM AUTHOR]

The recent discovery of large oil and gas fields in the deep-water of the Senegal Basin has drawn global attention. Despite this, several exploration wells in this area fail, which can be primarily contributed to a lack of understanding of the basin's structures and hydrocarbon accumulation conditions. This study examines these characteristics utilizing gravity, seismic and drilling data, and finally makes a comparison with the Cote d'Ivoire Basin, a typical transform margin basin in the South Atlantic. The results suggest that the Senegal Basin, influenced by multiple transform faults and a weak Paleozoic basement, experienced three evolutionary stages: rifting, transitional, and drifting. Each stage contributed to the development of distinct depositional sequences - syn-rift sequences, sag sequences, and continental margin sequences, respectively. The Triassic - Early Jurassic rifting stage predominantly formed continental deposits, like fluvial, lacustrine, and deltaic deposits, in the syn-rift sequences. The Middle-Late Jurassic transitional stage, influenced by transform faults, witnessed the formation of marginal ridges or submarine uplift zones. These zones, in conjunction with landward high terrains, formed a restricted environment promoting the development of source rocks in the sag sequences. During the drifting stage, three types of reservoirs, namely platform carbonate rocks, deltas, and slope-floor fans were formed. Notably, large-scale hydrocarbon reservoirs have been found in the deltas and the slope-floor fans both in the Senegal Basin and the Cote d'Ivoire Basin. The Upper Jurassic - Aptian platforms exhibit thick carbonate rocks and organic reefs on their edges, suggesting substantial potential for hydrocarbon exploration in the Senegal Basin. [ABSTRACT FROM AUTHOR]

The integrated simulation and optimization technology of reservoir-wellbore-pipe network is developed to reflect the mutual influence and restriction among reservoir engineering, oil production engineering and surface engineering, and to obtain the scheme with minimum conflict and optimal benefit in each step. This technology is based on the concept of global optimization to maximize production and profit, reduce costs and increase benefit. This paper elaborates the current situation of integrated simulation technology of reservoir-wellbore-pipe network both at home and abroad, discusses its correlation with the primary business of Sinopec and its development from three aspects of modeling, cloud platform and intellectualization. Suggestions on its future development are put forward from underlying data, software platform, popularization and application, and cross-border integration to provide means and guidance for the construction of intelligent oil and gas fields. The results show that the integrated simulation of reservoir-wellbore-pipe network can better reflect the optimization requirements of each step, avoid the ineffective operation of field equipment, and effectively improve the efficiency of research and management. Coupling solution, global optimization method and pressure fitting, which can make the simulation results reflect the real situation, are the key technologies for the network. The theoretical technology and main function research of integrated simulation technology have been mature, but the large-scale application and local function improvement of oil and gas fields are yet to be promoted. In the future, the integrated simulation of reservoir-wellbore-pipe network will develop from digitalization to modeling and intellectualization, from local simulation to cloud computing, and from manual intervention to intelligent decision-making. We suggest speeding up the construction of the unified database and model base of the whole underlying platform, strengthening the construction of software integration and integration platform with independent intellectual property rights, speeding up the popularization and application of intelligent oil and gas field demonstration projects, and strengthening the integration of oil and gas industry with artificial intelligence (AI), big data and block chain for its development. [ABSTRACT FROM AUTHOR]

Foam drainage agents enhance gas production by removing wellbore liquids. However, due to the ultra-high salinity environments of the Hechuan gas field (salinity up to 32.5 × 104 mg/L), no foam drainage agent is suitable for this gas field. To address this challenge, we developed a novel nanocomposite foam drainage system composed of quaternary ammonium and two types of nanoparticles. This work describes the design and synthesis of a quaternary ammonium foam drainage agent and nano-engineered stabilizers. Nonylphenol polyoxyethylene ether sulfosuccinate quaternary ammonium foam drainage agent was synthesized using maleic anhydride, sodium chloroacetate, N,N-dimethylpropylenediamine, etc., as precursors. We employed the Stöber method to create hydrophobic silica nanoparticles. Carbon quantum dots were then prepared and functionalized with dodecylamine. Finally, carbon quantum dots were incorporated into the mesopores of silica nanoparticles to enhance stability. Through optimization, the best performance was achieved with a (quaternary ammonium foam drainage agents)–(carbon quantum dots/silica nanoparticles) ratio of 5:1 and a total dosage of 1.1%. Under harsh conditions (salinity 35 × 104 mg/L, condensate oil 250 cm3/m3, temperature 80 °C), the system exhibited excellent stability with an initial foam height of 160 mm, remaining at 110 mm after 5 min. Additionally, it displayed good liquid-carrying capacity (160 mL), low surface tension (27.91 mN/m), and a long half-life (659 s). These results suggest the effectiveness of nanoparticle-enhanced foam drainage systems in overcoming high-salinity challenges. Previous foam drainage agents typically exhibited a salinity resistance of no more than 25 × 104 mg/L. In contrast, this innovative system demonstrates a superior salinity tolerance of up to 35 × 104 mg/L, addressing a significant gap in available agents for high-salinity gas fields. This paves the way for future development of advanced foam systems for gas well applications with high salinity. [ABSTRACT FROM AUTHOR]

Helium is an irreplaceable strategic mineral resource, and commercial helium-rich gas fields (He>0.1%) worldwide are typically discovered serendipitously during hydrocarbon exploration efforts. According to an analysis of 75 helium-rich gas fields and 1048 natural gas samples worldwide, helium in natural gas generally exhibits "scarce", "accompanying", and "complex" properties, and helium-rich gas fields often occur at depths <4500 m. Helium concentrations in He-CH4 and He-CO2 gas fields are notably lower than those in He-N2 gas fields (He>1%). However, geological reserves in the former two types of gas fields are mainly in the range of 107–1011 m3, whereas in the latter, they are only in the range of 105–107 m3. There are nevertheless notable disparities in the genesis and migration patterns between helium and gaseous hydrocarbons. Helium necessitates carriers (such as formation water, hydrocarbon fluids, N2, mantle-derived fluids, etc.) during both accumulation and long-distance migration processes, where migration conduits are not confined to sedimentary strata, and may extend to the basin's basement, lower crust, and even lithospheric mantle. However, the accumulation conditions of both helium and gaseous hydrocarbons are generally considered equivalent. The presence of gaseous hydrocarbons facilitates both the rapid exsolution of helium within helium-containing fluids and subsequent efficient aggregation in gaseous hydrocarbons, while both reduce helium diffusion and diminish escape flux. In terms of caprock, gypsum, salt, and thick shale as sealing layers contribute to the long-term preservation of helium over geological timescales. Large helium-rich gas fields, predominantly crust-derived gas fields, are primarily concentrated in uplifted zones of ancient cratonic basins and their peripheries. Based on a diagram of the He concentration versus He/N2 ratio, crust-derived helium fields can be categorized as basement, combined basement-sedimentary rock, and sedimentary rock helium supply types. Comprehensively given China's helium grade, helium resource endowment, natural gas industrialization process, and current helium purification processes, the foremost deployment zones for the commercial production of helium should be the helium-rich gas fields located in the Ordos, Tarim, Sichuan, and Qaidam Basins in western and central China. In addition, certain (extra) large helium-containing gas fields serve as important replacement zones. [ABSTRACT FROM AUTHOR]

The article summarizes the results of the authors' work on the comprehensive substantiation of the geological, tectonic and geofluid-dynamic conditions of hydrocarbon generation and accumulation in the subsalt floor of the Astrakhan Arch inside the Caspian oil and gas province. We analyzed a significant amount of archival geological and geophysical data and materials such as (i) an array of regional seismic profiles; (ii) gravity and magnetic exploration data of different scales; (iii) results of deep drilling. Specific seismic geological bodies that are capable of serving as oil and gas reservoirs have been identified. For the first time in creating the geological model of the Astrakhan Arch, its location within the autoclave hydrocarbon system of the subsalt floor of the Central subprovince of the Caspian oil and gas Province (within the Astrakha—Jambay oil and gas accumulation zone) has been taken into account. This allowed us to substantiate the geofluid-dynamic nature of the number of large non-structural-type oil and gas reservoirs boundaries. It is opening up new possibilities for predicting oil and gas fields, including those with low sulfur content. Several generation-accumulation mini-hotbeds have been identified on the Astrakhan Arch, and in three of them—reservoirs with increased probability of discovering oil and gas fields. The main result of the study is the refinement of the initial total geological resources of hydrocarbons of the Astrakhan Arch and adjacent areas. [ABSTRACT FROM AUTHOR]

Although the early‐Precambrian crystalline basement is now only sporadically exposed in the northern and south‐western parts of the Yangtze Block, it is supposed to have a widespread distribution beneath its Neoproterozoic and Phanerozoic covers. Here we present results of regional aeromagnetic data processing in consideration of remanent magnetization to investigate the spatial distribution of the early‐Precambrian basement buried deep under the Upper Yangtze Block and surrounding areas. The direct analytic signal amplitude of the aeromagnetic anomalies, which is less affected by the magnetization direction, reveals a broader basement below the Sichuan Basin, extending far north to the Micang Mountain. A comparison between the direct analytic signal amplitude with the reduction to the pole aeromagnetic anomalies indicates that possible remanent magnetization exists beneath the Micang Mountain near the boundary between the Qinling Orogen and Sichuan Basin. The automatic depth from extreme points transform is then performed on the direct analytic signal amplitude to estimate the depth to the early‐Precambrian crystalline basement. A synthetic model of a magnetic interface with remanent magnetization and random noise shows that the depth from extreme points method is able to resolve variable basement depths. Application of the depth from extreme points method to the direct analytic signal amplitude of the Upper Yangtze Block presents meaningful results about the early‐Precambrian crystalline basement undulations. It is shallow and uplifted beneath the Sichuan Basin, extending north to the Qinling‐Dabie Orogen, probably corresponding to the ancient Chuanzhong palaeo‐uplift. Although it gradually deepens to the east, the deepest basement is buried under the Jiangnan Orogen, which is likely associated with the collision‐induced crustal thickening between the Yangtze and Cathaysia blocks during the assembly of the Columbia supercontinent. Large gas fields around the Sichuan Basin are found at the slopes or depressions between basement uplifts, indicating that the deep marine carbonate rocks in the south and east of Sichuan Basin, particularly those located at the slopes or depressions between ancient basement uplifts, are favourable targets for further petroleum exploration. [ABSTRACT FROM AUTHOR]

In 1989, the first prolific hydrocarbon reservoirs were discovered by Saudi Aramco in the highly porous and permeable friable continental sandstones (Unayzah reservoirs) and shallow marine carbonates (Khuff reservoirs) of the Paleozoic successions in the south of Riyadh, central Arabia. Since 1989, Saudi Aramco has discovered new oil and gas fields in various stratigraphically and genetically different units of the Permo-Carboniferous and Permian successions. These successions were strongly affected by tectonic movements (Caledonian and Hercynian orogenesis) and Early and Late Paleozoic Gondwana glaciations. Therefore, the thickness of some sections was fully eroded or significantly reduced. The sequence stratigraphic interpretation of the Paleozoic successions allowed us to understand the depositional environments and regional distribution of the source, reservoir, and cap rock facies in improved palynologic studies. Hydrocarbons were discovered with the Late Permian continental sandstones of the Unayzah Formation, the glaciogenic sandstones of the Late Ordovician Sarah Formation in Saudi Arabia, Late Silurian Hazro reservoir in southeast Türkiye, and the cold desert eolian sandstones of the Permo-Carboniferous Haradh Formation. Potential source rock facies of the Qusaiba Shale Member in Saudi Arabia and the hot shale facies of the Dadaş Formation in southeast Türkiye were deposited at the base of the Early Silurian regional transgression (444 Ma) during the melting phase of the huge Gondwana ice mass. The hydrocarbons migrated downward into the glaciogenic reservoir sandstones due to the hydrostatic pressure provided a useful depositional environment model. The hydrocarbon discoveries have provided core and well log data for regional correlations. Every aspect of the sequence stratigraphy was investigated and various types of unconformities, sequence boundaries, glaciation periods, and maximum flooding surfaces were recognized and correlated between Middle East countries. The relationship between the sea-level fluctuations and sediment supply into the basin was established by the regressive (progradational) and transgressive parasequences and parasequence sets. This genetic sequence stratigraphic approach has significantly increased the hydrocarbon explorations and production in the entire Arabian Platform. [ABSTRACT FROM AUTHOR]

Considering the problems in the discrimination of fracture penetration and the evaluation of fracturing performance in the stimulation of thin sand-mud interbedded reservoirs in the eighth member of Shihezi Formation of Permian (He-8 Member) in the Sulige gas field, a geomechanical model of thin sand-mud interbedded reservoirs considering interlayer heterogeneity was established. The experiment of hydraulic fracture penetration was performed to reveal the mechanism of initiation-extension-interaction-penetration of hydraulic fractures in the thin sand-mud interbedded reservoirs. The unconventional fracture model was used to clarify the vertical initiation and extension characteristics of fractures in thin interbedded reservoirs through numerical simulation. The fracture penetration discrimination criterion and the fracturing performance evaluation method were developed. The results show that the interlayer stress difference is the main geological factor that directly affects the fracture morphology during hydraulic fracturing. When the interlayer stress difference coefficient is less than 0.4 in the Sulige gas field, the fractures can penetrate the barrier and extend in the target sandstone layer. When the interlayer stress difference coefficient is not less than 0.4 and less than 0.45, the factures can penetrate the barrier but cannot extend in the target sandstone layers. When the interlayer stress difference coefficient is greater than 0.45, the fractures only extend in the perforated reservoir, but not penetrate the layers. Increasing the viscosity and pump rates of the fracturing fluid can compensate for the energy loss and break through the barrier limit. The injection of high viscosity (50-100 mPa·s) fracturing fluid at high pump rates (12-18 m3/min) is conducive to fracture penetration in the thin sand-mud interbedded reservoirs in the Sulige gas field. [ABSTRACT FROM AUTHOR]

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

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

Amplitude variation with azimuth methods have a huge advantage in predicting small-scale fractures. However, the technique of using post-stack seismic data to predict fractures has rarely been investigated, with the main limiting factor being the degradation of resolution due to the stacking process, which makes it difficult to effectively identify small fractures. With the exploration and development of oil and gas fields entering into deeper levels, the traditional post-stack fracture prediction techniques often fail to meet the requirements of fine development. In this study, we propose a post-stack fracture enhancement technique based on phase decomposition. The technique advances parity phase decomposition based on the matched pursuit algorithm to extract the dominant phases in the seismic record, and the filtering process is carried out by the bidimensional empirical mode decomposition, which in turn computes the improved post-stack coherence and similarity attributes. Applying this method to 3D seismic datasets in the Sichuan region, the results indicate that the approach improves the seismic data quality and enhances the seismic attribute identification of fractures. The phase decomposition-based post-stack fracture enhancement technique shows significant potential in improving the signal quality of multidimensional seismic features such as texture, dip, and likelihood compared to traditional methods. This new technique provides a new way for fracture detection and characterization using post-stack seismic data, which can help to meet the needs of fine oilfield exploration and development. [ABSTRACT FROM AUTHOR]

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

Copyright of Coal Science & Technology (0253-2336) is the property of Coal Science & Technology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The Yan'an gas field in the Ordos Basin is a typical deep coalbed methane field with tremendous resource potential. Evaluation methods for gas content in deep coal seams are urgently required to be established. This study is aimed at quantitatively analyzing the gas content of coalbed methane in deep coalbed methane reservoirs and revealing its influencing factors. With the coal rock samples of typical deep coalbed methane wells in the Yan'an gas field of the Ordos Basin as the research objects, the gas-bearing characteristics of deep coal rocks were analyzed, and the main controlling factors of gas-bearing properties were explored. The research results indicate that (1) the deep coal seams in the Yan'an gas field have a considerable thickness, a high total organic carbon content, and the potential of pyrolysis hydrocarbon generation is generally elevated, presenting excellent hydrocarbon generation potential. (2) Various types of pores and fractures in the deep coal rocks of the Yan'an gas field are well-developed, providing a favorable preservation space and migration channel for deep coalbed methane. (3) The total gas content of on-site analysis of deep coalbed methane in the Yan'an gas field is relatively high, mainly existing in the form of free gas, and has significant exploration and development potential. (4) The gas content of deep coal rocks in the Yan'an gas field is jointly controlled by multiple factors such as the total organic carbon content, minerals, and pore structure. In conclusion, the deep coal seams in the Yan'an gas field have favorable reservoir-forming conditions and great exploration and development potential. [ABSTRACT FROM AUTHOR]

Current shale gas well production capacity predictions primarily rely on analytical and numerical simulation methods, which necessitate extensive calculations and manual parameter tuning and produce lowly accurate predictions. Although employing neural networks yields highly accurate predictions, they can easily fall into local optima. This paper suggests a new way to use Cuckoo Search (CS)-optimized neural networks to make shale gas well production capacity predictions more accurate and to solve the problem of local optima. It aims to assist engineers in devising more effective development plans and production strategies, optimizing resource allocation, and reducing risk. The method first analyzes the factors influencing the production capacity of shale gas wells in a block located in western China through correlation coefficients. It identifies the main factors affecting the gas test absolute open flow as organic carbon content, small-layer passage rate, fracture pressure, acid volume, pump-in fluid volume, brittle mineral content in the rock, and rock density. Subsequently, we used the CS algorithm to conduct the global training of the neural network, avoiding the problem of local optima, and established a neural network model for predicting shale gas well production capacity optimized by the CS algorithm. A comparative analysis with other relevant methods demonstrates that the CS-optimized neural network model can accurately predict production capacity, enabling a more rational and effective exploitation of shale gas resources, which lower development costs and increase the economic returns of oil and gas fields. Compared to numerical simulation, SVM, and BP neural network algorithms, the CS-optimized BP neural network (CS-BP) exhibits significantly lower prediction error. Its correlation coefficient between predicted and actual values reaches as high as 0.9924. Verification experiments conducted on another shale gas well also demonstrate that, in comparison to the BP neural network algorithm, CS-BP offers superior prediction performance, with model validation showing a prediction error of only 0.05. This study can facilitate more rational and efficient exploitation of shale gas resources, reduce development costs, and enhance the economic benefits of oil and gas fields. [ABSTRACT FROM AUTHOR]

Copyright of Kufa Studies Center Journal is the property of Republic of Iraq Ministry of Higher Education & Scientific Research (MOHESR) and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The geological reservoir characteristics and mechanical parameters of oil and gas fields exert significant influence on the stability and preliminary feasibility assessment of underground gas storage facilities, posing an urgent challenge for petroleum engineers to address. This study, grounded in the geological conditions and fundamental characteristics of the Wanshunchang gas field, explores the effects of various factors on stability parameters of gas storage facilities and analyzes the reasons underlying differences in stability. The findings reveal that the geological and mechanical parameters of the Wanshunchang gas field meet the basic requirements for gas storage facilities and can withstand injection and extraction pressures of up to 80 MPa. Furthermore, an increase in reservoir elastic modulus and cohesive strength mitigates reservoir leakage and contributes to maintaining wellbore stability in underground gas storage. Additionally, the pressure and curvature of the overlying strata are important factors affecting the permeability characteristics and stability of gas storage facilities. However, at a reservoir depth of 3000 meters, low leakage rates (23 ml/h) and reservoir damage (8%) can be achieved, highlighting the potential for establishing gas storage facilities with minimal adverse effects. Through comprehensive analysis of the geological reservoir characteristics of the Wanshunchang gas field, optimal parameter configurations suitable for gas storage facilities can be identified, elucidating the stability mechanisms thereof. This study provides essential data support for the Wanshunchang gas field as a potential site for underground gas storage. [ABSTRACT FROM AUTHOR]

In recent years, with the gradual increase of oil and gas exploration, the produced water of oil and gas fields has increased year by year, bringing many environmental problems, and the content of associated elements such as lithium, potassium and bromine in the produced water of some oil and gas fields has exceeded the industrial mining grade, which is suitable for comprehensive mining or separate mining. Therefore, it is of great practical significance to analyze the feasibility of comprehensive utilization of associated elements in oil and gas field water and put forward feasible technical routes. The water quality characteristics and resource distribution characteristics of oil and gas field water were summarized. And the research and applications of extraction technologies of associated elements lithium, bromine and potassium from deep brine such as the produced water of oil and gas field were anatomized. The applicability and existing problems of lithium, bromine, and potassium extraction technologies in salt lake brine for oil and gas field water were elaborated. Combined with the extraction technologies and applications of associated elements in oil and gas field water, it is considered that extraction of lithium by adsorption, extraction of potassium by hot solution and cold crystallization (or cold decomposition-flotation process) and bromine extraction by electrooxidation are feasible technical routes for comprehensive utilization of associated valuable elements in oil and gas field water. At present, the industrialization of oil and gas field water is only aimed at lithium extraction, and the whole process of comprehensive utilization of associated resources should be opened up as soon as possible, and the comprehensive utilization of oil and gas field water associated resources and standard treatment process should be sought for environmental protection and economy, so as to provide theoretical support for further industrial application and help the green and high- quality development of the oil and gas industry. [ABSTRACT FROM AUTHOR]

The Eastern Mediterranean is undergoing rapid transformations, increasing its importance in current international affairs for four main reasons: i) the energy dimension and the discovery of natural gas fields; ii) the new geopolitical dynamics testing the balance of power between states; iii) the refugee crisis; and iv) the renewed presence of external great powers. In this framework, the article explores the role of Italy and Turkey in the Eastern Mediterranean region with a focus on energy issues and the refugee crisis. It also analyses China's growing influence in this region and in Italy in the context of its Belt and Road Initiative (BRI) and the implications of these policies for the European Union. [ABSTRACT FROM AUTHOR]