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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]

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 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]

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]

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]

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]

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.)

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 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]

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]

Copyright of Boletin de Geologia is the property of Universidad Industrial de Santander 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.)

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]

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]

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.)

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]

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]

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]

Copyright of Codrul Cosminului is the property of Codrul Cosminului 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.)

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]

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]

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]

Fracturing horizontal well casing deformation has become very prominent, particularly in tectonic stress-concentrated shale gas fields, limiting the efficient development progress of shale gas. The main failure mode of casing shearing deformation had been attributed to fault slip caused by multi-fracturing. The current research did not provide a clear picture of the dynamic evolution relationship between hydraulic fracturing, fault slip, and casing deformation. In this paper, the dynamic model of fault slip induced by formation pressure change is established, incorporating the effects of stress drop, physical change of friction, and casing and cement-sheath resistance loads. The discontinuous displacement approach and explicit/implicit coupling iteration methods are used to reveal the relationships between the effective normal stress, shear stress, friction coefficient, and sliding velocity during the fault slip process. Furthermore, the microscopic process of casing deformation sheared by fault slip is investigated using static equilibrium theory, and a characterization method for determining the amount casing deformation caused by real-scale fault slip is proposed. The results show that three stages exist in the process of casing deformation sheared by fault slip, including trigger activation stage, accelerated slip stage, and deceleration slip stage. Fault slip is clearly influenced by fault strike. To reduce the amount of fault slip, the fault direction with the maximum in-situ stress should be avoided as much as possible. Serious casing deformation still occurs for large-scale activated faults even though the optimization measure of wellbore structure has been well taken. To fundamentally reduce the possibility of casing shear deformation, it is necessary to prevent fault slip through optimizing the design of hydraulic fracturing. This study lays the theoretical groundwork for the casing deformation control method in shale gas wells. [ABSTRACT FROM AUTHOR]

Completion fluids play a vital role in well-related processes within the oil extraction industry. This article presents a comprehensive study of the properties and performance of various brine solutions as completion fluids for different well and reservoir conditions. Attributes examined include density, corrosion resistance, temperature stability, compatibility with formation fluids, clay swelling potential and influence on wettability. The research highlights the significance of selecting appropriate completion fluids to optimize well and reservoir operations. Zinc chloride emerges as an excellent option for high density applications, while sodium chloride and potassium formate solutions are ideal for extreme cold conditions. Potassium acetate outperforms calcium chloride and potassium chloride and has excellent pH stability. The compatibility of completion fluids with formation water has been observed to be excellent, with no sedimentation or emulsion formation. Potassium acetate also experiences minimal clay swelling, making it suitable for clay-rich formations. On the other hand, calcium chloride has a higher clay swelling than most of the brines tested, making it less suitable for sandstone formations with a higher clay content than these brines. The research evaluates the water-wetting abilities of completion fluids in carbonate and sandstone formations. Potassium chloride and zinc chloride have the most significant impact in carbonate formations, while potassium acetate and potassium formate excel in sandstone formations. This study provides a comprehensive understanding of completion fluids, facilitating informed decisions that maximize operational efficiency, protect reservoir integrity, and enhance hydrocarbon recovery. The appropriate selection of completion fluids should align with specific well and reservoir conditions, considering the priorities of the application. [ABSTRACT FROM AUTHOR]

Natural gas extraction is a critical driver of the economy in western North America. Ecological reclamation is important to ensure surface disturbance impacts associated with natural gas development are not permanent and to assist native biota. Previous studies in semi-arid natural gas fields within Sublette County, Wyoming, USA have shown insects respond favorably to 1–3-year-old well pads undergoing reclamation compared to older successional reference vegetation communities dominated by Wyoming big sagebrush (Artemisia tridentata spp. Wyomingensis). Here, we examined well pads which were initially seed 5, 8, 10, 11, and 12 years prior to our study. We used a free, image-based software called SamplePointv. 1.60 to quantify vegetation on these well pads and adjacent reference areas from cell phone camera photographs. Insects were collected with a sweep net and identified to the family and morphospecies level. Statistical analyses were conducted to compare both vegetation and insect communities between reclamation sites and their paired reference area. We found little statistical difference between vegetation communities across our study but found significantly more insect abundance on reclaimed well pads than reference areas in 3 of 5 years and significantly higher family and morphospecies richness on reclaimed well pads in 4 of 5 years. A total of 2036 individual insects representing 270 species from 71 families across 11 orders were identified across this study. A total of 1557 individuals (76.5%) were found on reclamation sites, whereas 479 (23.5%) were found in reference areas across the entire study. A total of 233 species (86.3% of total) were found on reclamation sites, whereas 121 species (44.8% of total) were found in reference areas across the entire study. A total of 67 families (94.4% of total) were found on reclamation sites, whereas 45 families (63.4% of total) were found in reference areas across the entire study. All 11 orders found in the study were found on reclamation sites, whereas 9 orders were found in reference areas across the entire study. Our results suggest reclamation of natural gas well pads within an old successional stand of sagebrush continues to support higher levels of insect biodiversity and abundance for at least 12 years. As insects are the most diverse group of animals on Earth and because they provide a wide array of ecosystem services, our findings suggest ecological reclamation plays an important role in returning biodiversity and ecosystem functionality to a semi-arid and old successional sagebrush–steppe ecosystem. [ABSTRACT FROM AUTHOR]

Saline aquifers have been used for CO2 storage as a dedicated greenhouse gas mitigation strategy since 1996. Depleted gas fields are now being planned for large-scale CCS projects. Although basalt host reservoirs are also going to be used, saline aquifers and depleted gas fields will make up most of the global geological repositories for CO2. At present, depleted gas fields and saline aquifers seem to be treated as if they are a single entity, but they have distinct differences that are examined here. Depleted gas fields have far more pre-existing information about the reservoir, top-seal caprock, internal architecture of the site, and about fluid flow properties than saline aquifers due to the long history of hydrocarbon project development and fluid production. The fluid pressure evolution paths for saline aquifers and depleted gas fields are distinctly different because, unlike saline aquifers, depleted gas fields are likely to be below hydrostatic pressure before CO2 injection commences. Depressurised depleted gas fields may require an initial injection of gas-phase CO2 instead of dense-phase CO2 typical of saline aquifers, but the greater pressure difference may allow higher initial injection rates in depleted gas fields than saline aquifers. Depressurised depleted gas fields may lead to CO2-injection-related stress paths that are distinct from saline aquifers depending on the geomechanical properties of the reservoir. CO2 trapping in saline aquifers will be dominated by buoyancy processes with residual CO2 and dissolved CO2 developing over time whereas depleted gas fields will be dominated by a sinking body of CO2 that forms a cushion below the remaining methane. Saline aquifers tend to have a relatively limited ability to fill pores with CO2 (i.e., low storage efficiency factors between 2 and 20%) as the injected CO2 is controlled by buoyancy and viscosity differences with the saline brine. In contrast, depleted gas fields may have storage efficiency factors up to 80% as the reservoir will contain sub-hydrostatic pressure methane that is easy to displace. Saline aquifers have a greater risk of halite-scale and minor dissolution of reservoir minerals than depleted gas fields as the former contain vastly more of the aqueous medium needed for such processes compared to the latter. Depleted gas fields have some different leakage risks than saline aquifers mostly related to the different fluid pressure histories, depressurisation-related alteration of geomechanical properties, and the greater number of wells typical of depleted gas fields than saline aquifers. Depleted gas fields and saline aquifers also have some different monitoring opportunities. The high-density, electrically conductive brine replaced by CO2 in saline aquifers permits seismic and resistivity imaging, but these forms of imaging are less feasible in depleted gas fields. Monitoring boreholes are less likely to be used in saline aquifers than depleted gas fields as the latter typically have numerous pre-existing exploration and production well penetrations. The significance of this analysis is that saline aquifers and depleted gas fields must be treated differently although the ultimate objective is the same: to permanently store CO2 to mitigate greenhouse gas emissions and minimise global heating. [ABSTRACT FROM AUTHOR]

Carbon dioxide capture and storage (CCS) is a necessary requirement for high-emitting CO2 industries to significantly reduce volumes of greenhouse gases released into the atmosphere and mitigate climate change. Geological CO2 storage into depleted oil and gas fields is the fastest and most accessible option for CCS deployment allowing for re-purposing existing infrastructures and utilizing significant knowledge about the subsurface acquired during field production operations. The location of such depleted fields in the neighborhoods of high-emitting CO2 industries is an additional advantage of matured on-shore European fields. Considering these advantages, oil and gas operators are now evaluating different possibilities for CO2 sequestration projects for the fields approaching end of production. This article describes an integrated approach to reservoir simulations focused on evaluating a CO2 injection pilot at one of these matured fields operated by MND and located in the Czech Republic. The CO2 injection site in focus is a naturally fractured carbonate reservoir. This oil-bearing formation has a gas cap and connection to a limited aquifer and was produced mainly by pressure depletion with limited pressure support from water injection. The article summarizes the results of the efforts made by the multi-disciplinary team. An integrated approach was developed starting from geological modeling of a naturally fractured reservoir, integrating the results of laboratory studies and their interpretations (geomechanics and geochemistry), dynamic field data analysis (pressure transient analysis, including time-lapse) and history matching reservoir model enabling simulation of the pilot CO2 injection. The laboratory studies and field data analysis provided descriptions of stress-sensitive fracture properties and safe injection envelope preventing induced fracturing. The impact of potential salt precipitation in the near wellbore area was also included. These effects are considered in the context of a pilot CO2 injection and addressed in the reservoir simulations of injection scenarios. Single-porosity and permeability reservoir simulations with a dominating fracture flow and black-oil formulation with CO2 simulated as a solvent were performed in this study. The arguments for the choice of the simulation approach for the site in focus are shortly discussed. The reservoir simulations indicated a larger site injection capacity than that required for the pilot injection, and gravity-driven CO2 migration pathway towards the gas cap in the reservoir. The application of the approach to the site in focus also revealed large uncertainties, related to fracture description and geomechanical evaluations, resulting in an uncertain safe injection envelope. These uncertainties should be addressed in further studies in preparation for the pilot. The article concludes with an overview of the outcomes of the integrated approach and its application to the field in focus, including a discussion of the issues and uncertainties revealed. [ABSTRACT FROM AUTHOR]

In recent years, China has explored and exploited several high-pressure deep gas fields. Normally, high-pressure gas wells are gathered and processed through multichoke manifolds on well sites, creating hazards such as high wellhead flowing pressure (Pt) and high risk for on-site operation personnel. Moreover, downhole chokes have been used in place of surface chokes. In doing this, the Joule–Thomson (JT) effect is geothermally regulated, alleviating the formation of hydrates in surface facilities. However, its applicability to high-pressure gas wells is less explored. In an effort to guide its use, the objective of this study is to set selection criteria in terms of the allowable wellhead Pt and gas flow rate. First, isenthalpic lines are separately estimated for dry gas and high liquid hydrocarbon (LHC) content gas condensate at various inlet temperatures with the use of commercial software. Next, by analysis of the resulting isenthalpic curves, several results are obtained on the JT inversion curves and throttling process through a choke. Third, building on these insights, a method for projecting the maximum Pt is presented, leading to a value of 52.5 MPa. Finally, multiparameter models are separately run for two deep gas wells (8100 m and 5000 m), reinforcing the result of the pressure upper limit while maintaining a maximum daily gas production of 14 E4 m3. Both upper limits with a maximum Pt of 52.5 MPa and daily gas production of 14 E4 m3 are corroborated with field data records. These findings are vital to the selection of a viable high-pressure gas well for applying the downhole throttling technique. [ABSTRACT FROM AUTHOR]

Natural gas fields with economic helium (>0.3 He %) require the radioactive decay of crustal uranium (U) and thorium (Th) to generate He and tectonic/structural regimes favorable to releasing and concentrating He. An unknown is determining the role of faults and structural features in focusing deep‐seated He sources on shallow accumulations. We tested the correlation between high‐He wells (n = 94) and structural features using a new high‐resolution aeromagnetic survey in the Four Corners area, USA. A depth‐to‐basement map with basement lineaments/faults, an intrusion map, and a flattened basement structural high map were created using Werner deconvolution algorithms by combining magnetic, gravity, and topography data with magnetic and gravity depth profiles. We show quantitatively (via analysis of variance) that a non‐random process controls the relationship between He (>0.3%) and both basement faults and intrusions: 88% of high‐He wells occur <1 km of basement faults; and 85% of high‐He wells occur <1 km of intrusions. As He % increases, the distance to the structural features decreases. Strong spatial/statistical correlations of He wells to both basement faults and intrusions suggest that advective transport via faults/intrusions facilitates He migration. The role of gas phase buoyancy and structural trapping is confirmed: 88% of high‐He occurs within basement structural highs, and 91% of the remaining wells are <1 km from intrusions (potential structural high). We present a composite figure to illustrate how a probabilistic approach can be used as a predictive model to improve He exploration success by targeting zones of intersection of basement faults and intrusions within basement structural highs. Plain Language Summary: Helium, which is a colorless and odorless gas, is an important and irreplaceable commodity that is used in a variety of modern applications. Helium is often found comingled with natural gases in underground rocks. The exact importance of structural features in the accumulation of significant amounts of helium underground is largely unknown. In this study, we utilize high resolution geophysical techniques focused in the Four Corners Area, USA combined with geochemical data of helium sampled from oil/gas wells to investigate the role of structural features on helium's occurrence. We show that helium occurrences are not randomly related to structural features (basement faults and/or intrusions) using statistical tests. In fact, we show that helium percentages in natural gas increase as one moves closer to basement faults and/or intrusions. Furthermore, we suggest that these faults and intrusions likely help enable helium gas migration from deeper areas to shallower areas underground based on the strong spatial and statistical correlations of helium wells to basement faults and intrusions. We also construct a predictive composite figure using structural elements that are likely favorable to helium accumulation to aid in exploring new areas of undiscovered helium gas accumulations in the subsurface. Key Points: We show quantitatively (via analysis of variance) that a non‐random process controls the relationship between He (>0.3%) and both basement faults and intrusionsStrong correlations of He wells to both basement faults and intrusions suggest that advective transport via faults/intrusions facilitates He migrationWe present a predictive exploration model (intersection of basement faults and intrusions) that can be translated to other areas to generate He prospects [ABSTRACT FROM AUTHOR]

The Sebei gas field is in the Sanhu depression area of the Qaidam Basin, which is the main gas-producing area and a key profit pillar for the Qinghai oilfield. The Sebei gas field within the Qinghai oilfield is characterized by high mud content, poor lithology, interflow between gas and water layers, and a propensity for sand production. The reservoir rocks are predominantly argillaceous siltstone with primarily argillaceous cement. These rocks are loose and tend to produce sand, which can lead to blockage. During its development, the Sebei gas field exhibited significant issues with scale formation and sand production in gas wells. Conventional acidization technologies have proven to be slow acting and may even result in adverse effects. These methods can cause loose sandstone to disperse, exacerbating sand production. Therefore, it is necessary to elucidate the mechanisms of wellbore plugging and to develop an acidizing system for plug removal that is tailored to unconsolidated sandstone reservoirs. Such a system should not only alleviate gas well plugging damage but also maintain reservoir stability and ensure efficient and sustained stimulation from acidization treatments. In this paper, the stability of unconsolidated sandstone reservoirs and the acid dissolution plugging system, along with the technological methods for stabilizing sand bodies, are studied through mineral component analysis, acid dissolution experiments, core immersion experiments, and other laboratory tests. The principle of synergistic effects between different acids is applied to achieve "high-efficiency scale dissolution and low sandstone dissolution". Three key indicators of dispersion, sand dissolution rate, and scale dissolution rate were created. The acid plugging solution formula of "controlled dispersion and differentiated dissolution" was developed to address these indicators. Laboratory tests have shown that the sandstone is predominantly composed of quartz and clay minerals, with the latter mainly being illite. The primary constituent of the wellbore blockage scale sample is magnesium carbonate, which exhibits nearly 100% solubility in acid. By adding a stabilizer prior to acid corrosion, the core's corrosion can be effectively mitigated, particle dispersion and migration can be controlled, and the rock structure's stability can be maintained. Laboratory evaluations indicate that the scale dissolution rate is greater than or equal to 95%, the sand dissolution rate is below 25%, and the system achieves a differentiated corrosion effect without dispersion for 24 h. Field tests demonstrate that the new acid solution plugging removal system enhances average well production and reduces operational costs. The system effectively mitigates the challenges of substantial sand production and reservoir dispersion, thereby furnishing a theoretical foundation and practical direction for acid plugging treatments in unconsolidated sandstone gas fields. [ABSTRACT FROM AUTHOR]

Some of Beijing's recent assertive actions in the South China Sea can be understood as a manifestation of what Chinese analysts call 'independent development'. The concept is conceived as a responsive measure to what Beijing views as other claimants' unilateral hydrocarbon development activities in the South China Sea and as a means to pressure other claimants into engaging in joint development with China and to compensate for what Beijing perceives as the disadvantages it faces being a latecomer to the energy development race in the region. In attempting to conduct independent development, China has mostly targeted areas of the South China Sea that overlap with Vietnam's designated oil and gas development blocks. By contrast, when dealing with the Philippines, especially during the presidency of Rodrigo Duterte (2016-22), China has adopted the more loosely defined concept of 'cooperative development' to minimize potential legal and political barriers that Philippine leaders may face domestically. With Malaysia, China has traditionally been ambivalent to the prospect of joint development but may increasingly utilize independent development to nudge Malaysia into starting a serious discussion on joint development. However, pursuing independent development does not portend China's abandonment of joint or cooperative development. Indeed, there remains hope for regional collaboration in hydrocarbon development in the South China Sea. Keywords: South China Sea, energy, China, Vietnam, Philippines, Malaysia., There are an estimated 11 billion barrels of oil reserves and 190 trillion cubic feet of natural gas reserves in the South China Sea, as of 2019. (1) The economic [...]

The exploitation of deep unconventional gas resources has gradually become more significant attributing to their huge reserves and the severe depletion of convention gas resources in the world. The proportion of deep unconventional gas reservoirs in the total gas resources cannot be underestimated, including shale gas, tight gas, and gas of coal seam. Due to the low permeability and porosity, hydraulic fracturing technology is still an important means to develop deep unconventional gas resources. However, the presence of fracturing fluids and water accumulation at the bottom of the wellbore significantly reduce gas production. The liquid loading model can be used to determine when the gas well begins to load the liquid. In this work, different types of liquid loading models are classified, and the applicability of different models is analyzed. At present, the existing critical liquid carrying models can be divided into mechanism models and semi-empirical models. The model established by Turner is a typical mechanism model. There are great differences in the application of a critical liquid loading model between vertical and horizontal wells. The field cases of a liquid loading model in different gas fields are provided and discussed. The mechanism of liquid loading models in recent years is introduced and analyzed. The physical simulations and experimental work therein are described and discussed to clarify the feasibility of the modeling mechanism. This article also presents the limitation and future work for improving the liquid loading models. [ABSTRACT FROM AUTHOR]

Natural gas hydrate (NGH) is a potential future energy resource. More than 90% of NGH resources exist in the pore medium of seafloor sediments. During the development of deep-sea oil and gas fields, wellbore pipelines are often clogged due to the synthesis of gas hydrates, and the addition of thermodynamic inhibitors is a common solution to prevent hydrate synthesis. In this paper, the effects of two single inhibitors, sodium chloride and ethylene glycol, as well as hybrid inhibitors combining these two inhibitors on the synthesis of methane hydrates were investigated using the self-developed one-dimensional gas hydrate exploitation simulation test apparatus. The effects of single and hybrid inhibitors were investigated in terms of the hydrate synthesis volume and gas–water two-phase conversion rate. The results show that the hybrid inhibitor has a better inhibitory effect on hydrate synthesis with the same initial synthesis driving force. When the concentration of inhibitors is low, salt inhibitors can have a better inhibitory effect than alcohol inhibitors. However, in the mixed inhibitor experiment, increasing the proportion of ethylene glycol in the mixed inhibitor can more effectively inhibit the synthesis of hydrates than increasing the proportion of sodium chloride in the mixed inhibitor. [ABSTRACT FROM AUTHOR]

In order to further understand the complex spatial distribution caused by the extremely strong heterogeneity of buried hill reservoirs, this paper proposes a new method for predicting the development pattern of buried hill reservoirs based on the traditional pre-drilling prediction and post-drilling evaluation methods that mainly rely on seismic, logging, and core data, which are difficult to meet the timeliness and accuracy of drilling operations. Firstly, the box method and normalization formula are used to process and normalize the abnormal data of element logging and engineering logging, and then the stepwise regression analysis method is used to optimize the sensitive parameters of element logging and engineering logging. The Light Gradient Boosting Machine (LightGBM) algorithm, deep neural network (DNN), and support vector machine (SVM) are used to establish a new method for predicting the development pattern of buried hill reservoirs. Lastly, a comprehensive evaluation index F1 score for the model is established to evaluate the prediction model for the development pattern of buried hill reservoirs. The F1 score value obtained from this model's comprehensive evaluation index indicates that the LightGBM model achieves the highest accuracy, with 96.7% accuracy in identifying weathered zones and 95.8% accuracy in identifying interior zones. The practical application demonstrates that this method can rapidly and accurately predict the development mode of buried hill reservoirs while providing a new approach for efficient on-site exploration and decision-making in oil and gas field developments. Consequently, it effectively promotes exploration activities as well as enhances the overall process of oil and gas reservoir exploration. [ABSTRACT FROM AUTHOR]