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ABSTRACT 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]

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]

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]

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]

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]

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]

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 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.)

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]

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 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]

The success of CO2 storage projects largely depends on addressing formation damage, such as salt precipitation, hydrate formation, and fines migration. While analytical models for reservoir behaviour during CO2 storage in aquifers and depleted gas fields are widely available, models addressing formation damage and injectivity decline are scarce. This work aims to develop an analytical model for CO2 injection in a layer-cake reservoir, considering permeability damage. We extend Dietz's model for gravity-dominant flows by incorporating an abrupt permeability decrease upon the gas-water interface arrival in each layer. The exact Buckley-Leverett solution of the averaged quasi-2D (x, z) problem provides explicit formulae for sweep efficiency, well impedance, and skin factor of the injection well. Our findings reveal that despite the induced permeability decline and subsequent well impedance increase, reservoir sweep efficiency improves, enhancing storage capacity by involving a larger rock volume in CO2 sequestration. The formation damage factor d, representing the ratio between damaged and initial permeabilities, varies from 0.016 in highly damaged rock to 1 in undamaged rock, resulting in a sweep efficiency enhancement from 1–3% to 50–53%. The developed analytical model was applied to predict CO2 injection into a depleted gas field. [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]

Industrial exhaust gases and gas fields are two significant sources of carbon dioxide (CO2) emissions that contribute to the rising levels of CO2 in the atmosphere. Among the various emission reduction systems, the CCSU (Carbon Capture, Storage, and Utilization) system has garnered extensive attention and research. This research aims to obtain the superstructure network sequentially in the CCSU system using GAMS (General Algebraic Modeling System). A mathematical approach was developed to optimize the amount of CO2 stored and utilized by varying the time difference (dt) between the source and sink from 0 to 10 years. After calculating the economic potential (EP), it was found that the Carbon Capture and Storage (CCS) system for both sources has a negative impact. In contrast, the CCSU system enhances the economic potential (EP) by generating a positive value. This is possible as the captured CO2 can be sold to the utilization sink, thereby creating a revenue stream. The EP for CO2 reduction from gas fields is greater than that from the industry, 21.68 × 106 USD compared to 12.50 × 106 USD at dt min10 years. The CCSU system, when utilizing CO2 sources from gas fields, is more profitable compared to using industrial emissions. [ABSTRACT FROM AUTHOR]

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Gas well production involves various stages, including stable, variable, and declining production. However, existing production-capacity equations typically apply only to the stable production stage, limiting their effectiveness in evaluating gas well productivity across all stages. To address this, the material balance equation and Darcy's equation were employed to account for changes in average formation pressure due to pressure drop funnels. The concept of a pressure-conversion skin factor was introduced, and its approximation was developed, leading to the establishment and solution of a full-stage productivity equation. Numerical simulations were then conducted to verify the accuracy and applicability of this equation. The findings are as follows: ① The full-stage productivity equation remains effective even when production rates and pressure are not constant, with the only potential source of inaccuracy being the approximative solution for the pressure conversion-skin factor. ② Numerical simulations demonstrated that the approximate solution closely matched the numerical simulation results for average formation pressure across various production stages and fundamental parameters, showing a consistent trend and high precision. The approximate and independent approximation solutions for absolute open-flow capacity were nearly identical, indicating the full-stage productivity equation's applicability throughout the production of gas wells. ③ Application results revealed that the full-stage productivity equation offers superior accuracy compared to the modified isochronous well test. ④ The approximate solution generally provides slightly higher accuracy, and the independent approximate solution effectively eliminates the influence of gas leakage radius. Therefore, the use of the approximate solution is recommended to calculate the average formation pressure and the independent approximate solution to calculate the absolute open-flow capacity. The full-stage productivity equation developed in this study is not constrained by the production system, making it suitable for productivity evaluation across all stages of gas well production. This has significant implications for the effective development of gas fields. [ABSTRACT FROM AUTHOR]

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.)

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.)

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.)

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.)

The Rongchang–Dazu region in western Chongqing (eastern Sichuan Basin, China), known for its seismic activity, is a promising area for deep geothermal resource development; however, practical development is limited. Key geological understandings, such as heat flux, geothermal gradients, the nature of heat sources, thermal reservoir rock characteristics, and the classification of geothermal resources, remain in need of further study. In this work, the targeted area is surrounded by Sinian–Cambrian carbonate gas fields. An analysis of the deep geothermal prospects was conducted using exploration and development data from the Gaoshiti–Moxi gas fields within the Longwangmiao and Dengying Formations. The results indicate that the Rongchang–Dazu area has relatively high heat flow values and geothermal gradients within the Sichuan Basin, correlating with fault structure and seismic activity. Gas test data confirm that the Longwangmiao Formation in the study area reaches depths of 4000 to 4500 metres and exhibits anomalous pressures and temperatures exceeding 140 °C. Meanwhile, the Dengying Formation of the Sinian system lies at depths of 5000 to 5500 metres, with normal pressure, minimal water production, and temperatures exceeding 150 °C, characterising it as a dry-hot rock resource. Adjacent to western Chongqing, the Gaoshiti area within the Longwangmiao Formation, with an estimated flow rate of 100 kg/s, shows that the dynamic investment payback period is significantly shorter than the estimated 30-year life of a geothermal power plant, indicating strong economic viability. Deep geothermal resource development aids in conserving gas resources and enhancing the energy mix in western Chongqing. Future research should prioritise understanding the links between basement faults, seismic activity, and heat flow dynamics. [ABSTRACT FROM AUTHOR]

For Egypt, ethane is a vital chemical precursor, with the potential to significantly attract financial resources and drive economic growth. Enhancing its added value necessitates efficient recovery of ethane before it enters the national grid without processing. This research investigates the technical and economic feasibility of integrating natural gas liquids (NGLs) from three Egyptian NGLs plants—South Western Desert NGLs (SWD NGLs), North Western Desert NGLs (NWD NGLs), and East Mediterranean NGLs (EMD NGLs)—to improve ethane recovery from natural gas fields. The study focuses on revamping these NGLs plants using various NGLs recovery techniques, conducting a comprehensive comparison to identify the most effective methods for processing rich feed gas. Detailed design of the NGLs recovery processes was developed using HYSYS V.14 simulation software and supplementary calculation sheets. The design criteria encompass both technical and economic parameters to ensure a holistic approach in meeting project requirements. Results indicate a significant increase in ethane recovery: 16% for SWD NGLs, 10% for NWD NGLs (A, B, C), and 85% for EMD NGLs. This improvement will boost ethane feedstock for petrochemical companies from 2000 ton/day to 3500 ton/day, enabling increased polyethylene production. Economic analysis for the base case shows an expected internal rate of return (IRR) of 26%, a net present value (NPV) of USD 73 million, and a payback period of approximately 3 years. Sensitivity analysis on product prices, feed gas prices, and total capital investment confirms the project's economic viability, with all cases showing feasibility (IRR ≥ 15%) except when product prices fall below USD 225/ton for propane, USD 215/ton for liquefied petroleum gas (LPG), and USD 25/bbl for condensate. This study highlights the potential for enhanced ethane recovery, offering substantial economic benefits and supporting the growth of Egypt's petrochemical industry. [ABSTRACT FROM AUTHOR]

With the continuous surge of production data in the field of oil exploration and development, the difficulty of integration and analysis is increasing, and manual analysis methods are difficult to meet the development needs of oil and gas fields on site. Machine learning can accurately and efficiently process data, and is a key technology in the field of data analysis and optimization. Utilizing machine learning to solve difficult problems in oil and gas field development has become the main focus of the industry. However, due to limitations in standardization construction, sample library establishment, and on-site integration, there are still many challenges and shortcomings in the application of machine learning in the field of oil exploration and development. In the future, efforts should be made to strengthen the standardization construction of machine learning, improve the data processing ability of deep learning algorithms, and pro-mote interdisciplinary research in the field of deep machine learning. Through multiple approaches, we can jointly promote the significant development of machine learning in the oil and gas field industry. [ABSTRACT FROM AUTHOR]

Objective The drilling wastewater in a block of Changqing Oilfield is large in volume, complex in composition, and high in Ca2+ and other multivalent ions, which makes it challenging to meet the requirements of fracking fluid blending performance after conventional treatment. Methods Based on the above difficult process characteristics, a new type of calcium removal process was proposed by modifying chitosan with multifunctional groups to chelate Ca2+, and its effect on calcium removal, calcium removal mechanism, applicable conditions (temperature, pH), environmental impact (mud production) and back-mixing performance were evaluated. Results The results showed that chitosan with a high degree of deacetylation was used as raw material, potassium persulfate was used as initiator to graft acrylic acid, and chitosan: potassium persulfate: acrylic acid=1.0:1.2:25.0 was reacted under the conditions of temperature of 70 ℃ for 2 h to produce highly water-soluble multifunctional chelating agent, and the Ca2+ could be chelated and removed to less than 500 mg/L by using 600 mg/L SZ-1. SZ-1 could be applied under the conditions of 10-40 ℃, pH=6-14, with low sludge production (0.016 g/L) and suitable viscosity of base fluid (30.9~31.2 mPa?s), which satisfied the requirements of base fluid viscosity range (10-40 mPa?s) in SY/T 7627—2021 Technical requirements of water-based fracturing fluid. Conclusion It is expected to provide a new solution for the treatment of drilling wastewater with high calcium content in oil and gas fields, with its green and clean color, excellent performance, and simple preparation. [ABSTRACT FROM AUTHOR]

The structural complexities of hydrocarbon reservoirs make it difficult to correlate geological and petrophysical properties. A successful field development depends on accurately mapping the spatial distributions of reservoir key parameters. In this study, we present results on rock type analysis, estimation, and uncertainty evaluation of geological and petrophysical data of 33 wells in one of the south Iranian gas fields. This paper is divided into two parts. In the first part, we used a reservoir rock classification theme based on identifying electrofacies (EFs) and hydraulic flow units by analyzing both log and core data. In the second part of the paper, we performed estimation, uncertainty evaluation, and assessment of the porosity–thickness relationship of the high-quality EFs using geostatistical techniques. We used sequential simulation schemes to map the spatial distributions of porosity and thickness of the high-quality EFs across the field. Using probabilistic approaches, the generated multiple realizations were used to quantify the local and spatial uncertainties. Variogram analysis showed that property distributions had a higher continuity and minimum variance in the NW–SE direction. Based on spatial uncertainty analysis, we found that the indicator-based sequential simulated maps exhibited less spatial uncertainty. Furthermore, the obtained probability maps indicated that the SE part of the study area is more suitable for drilling and production scenarios. [ABSTRACT FROM AUTHOR]

The porosity of freshwater ice and sea ice is one of the main parameters that determine their strength. The strength of ice varies over a wide range of values, and the differences in the intensity of the mechanisms of ice porosity formation in different water areas can be one of the possible reasons for these variations. The water mass contains gases in two forms: gases dissolved in the water mass, as well as gas bubbles that are formed when wind waves break up, and bubbles that float up from the seabed. This article presents the results of an analysis of the role of each of these forms in the formation of gas inclusions (pores) in the crystal structure of ice. The results showed that the main source of gas pores in ice crystals is the gas bubbles coming to the surface from the bottom, formed during the decomposition of bottom sediments or during gas leaks from near-bottom oil and gas fields. The possibility of gas bubbles occurring and rising to the ice–water boundary depends on the presence of bottom sources of the gases, the intensity of dissolution of the bubbles and the depth of the water area. Therefore, the variation in the porosity and the strength of ice over the space of the water areas can be associated with the changes in their depths, and the presence and location of the natural gas sources. [ABSTRACT FROM AUTHOR]

For insight into the productive and storage mechanisms of biogas in the Qaidam Basin, efforts were made to investigate the groundwater recharge and the processes of hydrocarbon generation by CDOM-EEM (fluorescence excitation-emission matrix of Chromophoric dissolved organic matter) spectrum, hydrogen and oxygen isotopes, and geochemical characters in the central depression of the Qaidam Basin, China. The samples contain formation water from three gas fields (TN, SB, and YH) and surrounding surface water (fresh river and brine lake). The results indicate that modern precipitation significantly controls the salinity distribution and organic matter leaching in the groundwater system of the central depression of the Qaidam Basin. Higher salinity levels inhibit microbial activity, which leads to organic matter degradation and to gas generation efficiency being limited in the groundwater. The inhabitation effect is demonstrated by the notable negative correlation between the extent of organic matter degradation and its concentration with hydrogen and oxygen isotopes. The conclusion of this study indicated that modern precipitation emerges as a crucial factor affecting the biogas production and storage in the Qaidam Basin by influencing the ultimate salinity and organic matter concentration in the formation, which provides theoretical insight for the maintenance of modern gas production wells and the assessment of gas production potential. [ABSTRACT FROM AUTHOR]

Copyright of Industrial Water Treatment is the property of CNOOC Tianjin Chemical Research & Design Institute 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 most crucial elements in the oil and gas sector are predicting subsurface lithofacies utilizing geophysical logs for reservoir characterization and sweet spot assessment procedures. Nevertheless, accurately predicting payable lithofacies in a complex heterogeneous geological setting, such as the lower goru formation, poses considerable difficulty because conventional methods fall short in delivering highly accurate outcomes. Hence, this research proposes an advanced cost and time-saving data intelligence strategy using multiple classifiers to predict lithofacies with maximum accuracy that will aid in sweet spot evaluation in oil and gas fields globally. Geophysical log data of five wells from a mature gas field were used. The targeted reservoir formation was classified into seven facies types. We evaluated the performance of seven different models: support vector machine (SVM), K-nearest neighbors (KNN), random forest (RF), decision tree (DTr), naive Bayes (NB), adaptive boosting (AB), and ensemble (an integrated SVM, KNN, RF, and DTr classifier). RF and ensemble classifiers predicted the lithofacies with accuracies of 97.5 and 97.3%, respectively. Their efficacy in lithofacies prediction with high accuracy renders them as valuable tools in the domain of sweet spot evaluation. The proposed digital intelligence strategy could help operators identify drilling sites based on in-depth reservoir characterizations. [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 oil and gas field surface gathering pipeline network is an important hub for transporting oil and gas products outward, and its optimal design is crucial to reducing the construction cost of the pipeline system. Star-star topology is often applied to the layout of surface gathering pipeline networks in oil and gas fields. However, the optimization of star-star topology is often carried out under the constraint of the fixed station type, which may easily lead to a waste of station capacity and increase investment or make the optimization results meaningless. In this article, a mixed integer linear programming mathematical model for the overall optimization of star-star pipeline network layout considering the station location-allocation problem is constructed in discrete space with coupled station type constraints, and the branch-and-bound method is used to obtain the global optimal solution. Three cases verify the feasibility and effectiveness of the model and algorithm. The results show that the maximum avoided capacity waste is 20 × 104 m3/d and the maximum investment can be reduced by 8961.6 × 104 Yuan, which shows that the proposed model can effectively improve the economy and rationality of the pipeline system, and has important guiding significance for the construction of oil and gas fields. [ABSTRACT FROM AUTHOR]

Reservoir productivity prediction is a key component of oil and gas field development, and the rapid and accurate evaluation of reservoir productivity plays an important role in evaluating oil field development potential and improving oil field development efficiency. Fracture-vuggy reservoirs are characterized by strong heterogeneity, complex distribution, and irregular development, causing great difficulties in the efficient prediction of fracture-vuggy reservoirs' productivity. Therefore, a PSO-BP fracture-vuggy reservoir productivity prediction model optimized by feature optimization was proposed in this paper. The Chatterjee correlation coefficient was used to select the appropriate combination of seismic attributes as the input of the prediction model, and we applied the PSO-BP model to predict oil wells' production in a typical fracture-vuggy reservoir area of Tahe Oilfield, China, with the selected seismic attributes and compared the accuracy with that provided by the BP neural network, linear support vector machine, and multiple linear regression. The prediction results using the four models based on the test set showed that compared with the other three models, the MSE of the PSO-BP model increased by 23% to 62%, the RMSE increased by 12 to 38 percent, the MAE increased by 18 to 44 percent, the SSE increased by 23 to 62 percent, and the R-square value increased by 2 to 13 percent. This comparison proves that the PSO-BP neural network model proposed in this paper is suitable for the productivity prediction of fracture-vuggy reservoirs and has better performance, which is of guiding significance for the development and production of fracture-vuggy reservoirs. [ABSTRACT FROM AUTHOR]

Large-scale geological sequestration of CO2 is one of the most effective strategies to limit global warming to below 2 °C, as recommended by the Intergovernmental Panel on Climate Change (IPCC). Therefore, identifying and characterizing high-quality storage units is crucial. The Surma Basin, with its four-way dip closed structures, high-quality reservoirs, and thick regional cap rocks, is an ideal location for CO2 storage. This study focuses on the Bokabil Formation, the most prominent reservoir unit in the Surma Basin. Detailed petrographic, petrophysical, XRD, and SEM analyses, along with mapping, have been conducted to evaluate the properties of the reservoir and cap rock within this formation. The Upper Bokabil Sandstone in the Surma Basin ranges from 270 to 350 m in thickness and consists of fine- to medium-grained subarkosic sandstones composed of 70–85% quartz and 5–12% feldspar, with good pore connectivity. Petrophysical analysis of data from four gas fields indicates that this unit has a total porosity of 21–27.4% and a low shale volume of 15–27%. Cross plots and outcrop observations suggest that most of the shales are laminated within the reservoir. The regional cap rock, known as the Upper Marine Shale (UMS), ranges in thickness from 40 to 190 m and contains 10–40 nm nano-type pores. A higher proportion of ductile materials with a significant percentage of quartz in the UMS indicates higher capillary entry pressures, enhancing its capacity to hold CO2. Using the CSLF method with a 6% cut-off of the available pore volume, it is estimated that 103 Mt, 110 Mt, 205 Mt, and 164 Mt of CO2 can be effectively stored in the Sylhet, Kailashtila, Habiganj, and Fenchuganj structures, respectively. Due to the shallow depth of the storage unit and the thick cap rock, the southern Surma Basin is the optimal location for CO2 injection. [ABSTRACT FROM AUTHOR]

The exploitation and transportation of deep-sea and remote oil and gas fields have risen to become important components of national energy strategies. The gas–liquid separation and gas blocking caused by the large density difference between the gas and liquid phases are the primary influencing factors for the safe and reliable operation of gas–liquid mixed transportation pump systems. This paper takes the independently designed single-stage helical axial-flow mixed transportation pump compression unit as the research object. Through numerical simulation, the internal flow of the mixed transportation pump is numerically calculated to study the aggregation and conglomeration of small gas clusters in the flow passage hub caused by gas–liquid phase separation, influenced by the shear flow of phase separation, forming axial vortices at the outlet where gas clusters gather in the flow passage. The work performed by the impeller on the gas clusters is insufficient to overcome the adverse pressure gradient formed at the outlet of the flow passage due to the gathering of the liquid phase in adjacent flow passages, resulting in the phenomenon of gas blocking, with vortex gas clusters lingering near the hub wall of the flow passage. [ABSTRACT FROM AUTHOR]

The waste gas mud generated during the drilling process of the Yanchang gas field is treated with solid-liquid separation, oil/water recycling, and solidification of bottom mud. Research shows that after solid-liquid separation of waste mud, the reduction rate reaches 82.11%, and the oil recovery rate and water content in the recovered oil are 94.50% and 0.43%, respectively; after chemical oxidation floeeulation filtration treatment, the separated effluent has a light transmittanee of over 98. 5% and can be used for the repreparation of oilfield working fluids; the oil content in the sediment is 4.56%, and after solidification treatment, the compressive strength can reach 15.977 MPa. It can be used for laying well pads or roads in oil and gas fields, and the leachate from the solidified form meets the water quality requirements of the "Comprehensive Wastewater Discharge Standard". [ABSTRACT FROM AUTHOR]

Helium is an irreplaceable ore resource for many applications, such as nuclear magnetic resonance, aviation, semiconductors, and nuclear energy. Extracting helium in a free state from natural gas is currently the only economical approach at the industrial level. In this study, we compiled geochemical data of 719 natural gas samples from 36 oil and gas fields in the Tarim basin that include experimental results and previously reported data. Helium is of primarily crustal origin in the Tarim Basin according to helium isotope characteristics (not exceeding 0.1 Ra), except in the Ake gas field that has not more than 7% of mantle helium. Helium concentrations in diverse tectonic units vary considerably. Oil-type gas, on the whole, has a higher helium concentration relative to coal-type gas. Abundant helium flux, a favorable fault system between the source-reservoir system, no strong charging of gaseous hydrocarbons, and the good sealing capacity are important factors that control the formation of helium-rich gas fields. Considering both the helium concentration and natural gas reserves, helium-rich gas fields located in the Southwest Depression and Tabei Uplift can be regarded as the major favorable zones of further deployment for helium extraction. [ABSTRACT FROM AUTHOR]

The oil and gas trade is one of the main ways to promote regional economic development by improving the effectiveness of resource allocation. While regional energy cooperation could lead to growth in the energy trade, blind investment will reduce effective yields. Kazakhstan and China maintain a stable oil and gas trade, but resource exports to China are not growing as expected. The aim of this research is to analyze the competitiveness and complementarity of Kazakhstan and China in the oil and gas trade, as well as the main factors affecting the oil and gas trade between Kazakhstan and China. By creating a linear regression equation to analyze the gravity model of the oil and gas trade between Kazakhstan and China, it was revealed that a 1% growth of the gross domestic product in both countries would lead to a 1.471% increase in the oil and gas trade. However, an increase in oil and gas production in Kazakhstan will not contribute to the expansion of the oil and gas trade with China. Kazakhstan and China could improve their oil and gas trade by strengthening financial cooperation, improving energy efficiency, increasing investment in infrastructure such as oil refineries and pipelines, and developing new oil and gas fields in Kazakhstan. [ABSTRACT FROM AUTHOR]

Purpose: Life cycle assessment (LCA) has found wide applicability as a tool for assessing the environmental impacts of human activities in different fields such as manufacturing, mining, transportation, oil and gas, construction, and medicine. Despite the wide applicability of LCA globally, the uptake and use of the tool in Africa remains limited. This research is motivated by the need to explore the continental structure of life cycle assessment to ascertain the level of knowledge and research; collaboration amongst institutions, countries, and authors; keyword co-occurrence; thematic evolution; and bibliographic coupling. Methods: Publications related to life cycle assessment were retrieved and cleaned from the Scopus database with the language restricted to English and only countries recognised by the African Union. VOSviewer (version 1.6.19) visualisation tool was used to construct and visualise the network maps of researchers, co-occurrence, co-authorships, and keywords. On the other hand, Bibliometrix was employed to carryout descriptive analysis and thematic evolution and to extract bibliographic information. Results and discussion: In total, 616 research publications between 1992 and 2022 were retrieved. The results show that research on the subject matter picked up from 2004 and has been on the upward trend. South Africa, Egypt, Tunisia, and Algeria are the top countries carrying out LCA research on the continent. In addition, the top authors, affiliations, and funders also come from these countries. It was also noted that there were low levels of cooperation between authors on the African continent; rather, they collaborate more with researchers in Europe, America, and other parts of the world. The built environment, construction industry, alternative energy, agriculture, and waste management and recycling are the major themes of research on the continent. Conclusion: Life cycle assessment is gaining traction amongst researchers in Africa, albeit slowly. Considering the continents' role in the future especially in providing critical raw materials needed for the transition to a carbon-neutral society in line with the Sustainable Development Goals (SDGs), rapid uptake and embedding life cycle thinking in every sector of the African economy are needed. However, there is an urgent need to equip researchers with the skills to facilitate the development of a life cycle inventory (LCI) database at countries or continental level. [ABSTRACT FROM AUTHOR]

Stimulated reservoir volume (SRV) fracturing has become the most efficient technology in the treatment of unconventional hydrocarbon reservoir formations. This process aims to optimize well productivity by establishing an intricate network of fractures that integrate hydraulic and natural fractures, distal to the wellbore, thereby amplifying the contact area with the subterranean formations and fracture systems. This study introduces a quantitative framework designed to characterize the fracturing effects within naturally fractured unconventional hydrocarbon reservoirs. Leveraging existing fracturing treatment designs and production performance data, the study formulates a mathematical model of the complex fracture network, predicated on the principle of material balance. The model comprehensively accounts for the development degree of natural fractures, the morphological impact of stress differentials on the fracture network, and the imbibition displacement effects of the fracturing fluids. The model's accuracy is verified through an integration with microseismic monitoring data and an enhanced understanding of reservoir development. Building upon this foundation, the study quantitatively dissects the impact of various engineering parameters on the efficacy of SRV fracturing. The proposed quantitative characterization method is adept for widespread application across multiple wells in oil and gas fields, offering a distinct advantage for the swift and precise assessment of SRV fracturing outcomes in naturally fractured unconventional hydrocarbon reservoirs. The research method, which is based on readily accessible fracturing construction data and is more convenient, can to a certain extent improve the efficiency of hydraulic fracturing evaluation work. [ABSTRACT FROM AUTHOR]

In this study, the corrosion behavior of N80 and TP125V steels was delved firstly into produced water from shale gas fields containing CO2-O2. Moreover, the localized corrosion of these steels was investigated to elucidate the effects of aerobic and anoxic on steel corrosion. The results indicated that the corrosion rates of N80 and TP125V steels under aerobic conditions were lower compared to those in the presence of CO2-O2. Specifically, at temperature of 100 °C and with dissolved oxygen (DO) concentration of 4 mg/L in the CO2-O2 environment, the N80 and TP125V steels exhibited the highest corrosion rate, with values of 0.13 mm/y and 0.16 mm/y, respectively, as determined by specific weight loss measurements. Conversely, these rates decreased to 0.022 mm/y and 0.049 mm/y under aerobic conditions. Furthermore, severe localized corrosion of N80 and TP125V steels with a DO concentration of 4 mg/L was also observed in the CO2-O2 environment. Finally, it was evident that pitting corrosion is the predominant type of corrosion affecting N80 and TP125V steels in the produced water from shale gas fields. [ABSTRACT FROM AUTHOR]