Environmental radiological monitoring and risk assessment in shale gas areas.

3D modeling of source and reservoir rock characteristics in key oil and gas fields, Gippsland Basin, Southern Australia

Long-term emission of methane and ethane to the atmosphere from hybrid natural seepage and well leakage in the Sărmăşel gas field (Romania)

Calculation method of multi-stage gas lift process parameters in deep offshore low-permeability oil and gas fields

Abstract The problem of methane hydrate conversion into carbon dioxide hydrate during injection and boiling of liquid carbon dioxide in a formation containing methane and its hydrate is studied. Estimates show that the substitution reaction at the contact of methane hydrate and liquid carbon dioxide is impossible due to the low enthalpy of the liquid phase CO 2 . A mathematical model of the conversion is proposed, which assumes preliminary gasification of carbon dioxide. In this case, the formulated model contains two unknown moving boundaries of phase transitions separating three regions of different states of the components. Similarity solution is found, reducing the problem to a numerical study of a system of seven transcendental equations. The results of calculations of characteristic regimes of the process under consideration are presented. It is shown that with a decrease in the initial temperature of the reservoir or hydrate saturation, methane substitution by carbon dioxide does not occur.

Abstract Robert Tamsma was a professor of economic and human geography at the University of Groningen in the Northern Netherlands in the 1966–1987 period. The Northern Netherlands was then a prime target area for regional policy. At the same time, the province of Groningen experienced the discovery of what was then the largest natural gas field in the world, a possible new source of welfare. Both issues combined determined Tamsma’s profile in research, and the themes of his lectures and writings, that are still found as inspirations for present‐day economic geographers. In this paper, we look back on Tamsma’s time in Groningen, with personal memories that show that he was not only a very talented scientist, but also struggled with issues surrounding his leadership within the faculty community.

The bearing capacity of piles in soil is determined by both the mechanical properties of the soil and the method of pile installation. The widespread implementation of pile foundations in offshore oil and gas field development has highlighted significant deficiencies in the current domestic scientific, methodological, and regulatory approaches for evaluating pile–soil interaction. This study addresses the key issues and limitations in calculating bearing capacity for commonly used drilled-in and precast piles. For combined drilled-in piles, the existing methodology inaccurately assumes that the hydrostatic pressure exerted by the cement slurry on the borehole walls remains unchanged after hardening, leading to erroneous estimations. In the case of precast metal piles, the use of standardized regulatory tables results in substantial discrepancies compared to actual performance, particularly at depths exceeding 35 m, where these methods become completely inapplicable. Furthermore, the dynamic method outlined in building regulations—used to predict the bearing capacity of short precast piles driven using mechanical or hydraulic hammers in offshore environments—produces results with unacceptable margins of error. This method is also unsuitable for longer piles due to its inherent limitations. The root causes of the limitations in existing methods for evaluating the load-bearing capacity of pile foundations have been systematically investigated. Based on this analysis, the theoretical framework for a new calculation methodology has been developed. By integrating comprehensive laboratory data, a revised approach is proposed that significantly enhances the reliability and accuracy of the estimated bearing capacity, ensuring closer alignment with actual field performance. The bearing capacity and settlement of pile foundations for offshore hydraulic structures were computed and analyzed with consideration of the soil’s plastic deformation behavior.

No Abstract.

This article, based on a large array of geophysical and geological data, constructs a model of Syria's regional geological evolution and presents a classification of high-temperature and high-pressure wells. It also summarizes the geographic distribution of Syria's high-temperature oil and gas fields, which is important for developing a hydrocarbon exploration strategy.The article also describes the most well-known oil and gas wells considered high-temperature in Syria:– Al-Ezba-123 well in the Al-Ezba field, which is located approximately 25 km northeast of the Syrian city of Deir ez-Zor on the Euphrates River, near the border with Iraq and approximately 400 km northeast of the capital, Damacus;– Sadad-1 well in the Sadad gas field, located northwest of Sadad, in the city of Homs; its capacity ranges from 450,000 to 500,000 m3 of gas per day;– Abu Raba-3 well at the Abu Raba field, one of Syria's main gas fields, located east of Homs in the Al-Ferklus region, with a capacity of 300,000 cubic meters of gas per day;– Kara-1 well at the Kara field, located in the Qalamoun region on the outskirts of Damascus;– Sharifa-5 well at the Sharifa field, located in the eastern part of Homs, despite its shallow depth, and the bottomhole temperature does not exceed 80 °C.Many oil and gas fields are located at great depth, which creates various challenges during drilling, completion, and operation of wells. The temperature gradient at Syria's oil and gas fields is estimated at 3 °C per 100 m.Based on the presented study of the Euphrates Basin's sedimentary strata, it can be concluded that it contains a significant number of petroleum source rocks and productive reservoirs, indicating favorable geological factors that determine the petroleum potential of the Euphrates Basin's sedimentary cover. The plateau's petroleum potential is associated with Paleozoic, Triassic, Cretaceous, Paleogene, and Neogene deposits that make up the platform structures within the Euphrates Basin. According to a report by the Syrian Economic Working Group dated January 15, 2014, and information provided by the Syrian Petroleum Company, drilled structures at the final stage do not exceed 39 % of the total number of structures with potential petroleum potential. The Euphrates Plateau is considered promising and requires more detailed geological exploration.

Petroleum and natural gas are among the most critical energy sources in contemporary societies, still impossible to replace with recoverable resources. They are projected to play a pivotal role in addressing the global energy demands in the near future. Achieving energy security for the present turbulent times is of utmost importance. The discovery and development of new hydrocarbon deposits, along with increasing productivity from existing fields. The majority of onshore oil and gas fields in Bulgaria are in a mature to final stage of exploitation, thus emphasizing the need for innovative approaches and modern methods for outlining perspective exploration territories. Some of the economic oil fields are still in production (Tyulenovo, Dolni and Gorni Dabnik, Dolni Lukovit - Staroseltsi and Burdarski Geran) and their recoverable potential remains to be fully tapped. Conversely, a number of other fields have been classified as depleted or with minimal remaining reserves, which seriously raises the question of their future (e.g., Devetaki, Pisarovo, Aglen and Deventsi). These "depleted" deposits are of significant interest due to the possibilities to reassess and apply modern technologies for optimization and increasing the yield from already exhausted fields. Therefore, the primary goals are enhancing the recovery factor to prolong the operational lifespan of existing brownfields and reassessing the hydrocarbon perspective areas in Northern Bulgaria. Moreover, a significant set of geological, geophysical and technical data concerning hydrocarbon accumulations is available for reassessment. This extensive data base provides a robust foundation for contemporary characterization and evaluation of natural reservoirs in the case of Devetaki gas condensate field and overall evaluation of several perspective adjacent areas (Bohot, Gradina, Kriva Bara, Bazovets, Tarnak and etc.). It also facilitates quantitative estimations of resource and reserve volumes within these reservoirs as well as delineation of future exploration territories. The integration of software platforms with modern geoscience concepts offers a cost-effective tool for economic growth. This study highlights the need for realistic geological models and production plans to enhance recovery from mature oil and gas fields in Bulgaria. Reassessment of the promising areas where hydrocarbons are present will also provide a new in-depth view on the future oil and gas sustainable exploration.

In high-sulfur environments, the failure risk of completion tubing increases due to the coupling effect of mechanical and electrochemical corrosion during the acidification production process. The corrosion behavior of P110SS tubing steel was investigated by an HTHP corrosion weight loss experiment and an electrochemical corrosion experiment. Scanning electron microscopy (SEM) and energy-dispersive X-ray spectroscopy (EDS) were used to analyze the surface morphology of the corrosion products. In addition, a prediction model for the remaining service life of completion tubing under the synergistic effect of corrosion and stress was established during the acidification production process. The results show that acidification operations have a significant impact on the subsequent service life of tubing; the corrosion rate of P110SS tubing in the full acidification production process is much higher than that after the produced gas field solution corrosion treatment alone. Obvious pitting marks, micropores, and microchannels are observed in the corrosion product film of P110SS steel after acidification treatment, and the corrosion product film structure of P110SS steel is loose and honeycomb-like after acidification production treatment. The corrosion products are mainly FexSy and FeCO3 after acidification production corrosion treatment. The corrosion during the acidification production stage is controlled by cathodic polarization. The remaining service life of tubing after production corrosion treatment can reach up to 29 years, while the remaining service life of tubing after acidification production corrosion treatment is significantly reduced, with a maximum of only 8 years. The research results have guiding significance for the selection, optimization, and design of high-sulfur-gas well tubing.

OIL Terminal Constanța is one of the largest petroleum terminals in Eastern Europe, playing a strategic role in the transportation and storage of petroleum products for the European market. Its economic and operational importance is increasing, particularly in the context of the upcoming exploitation of the Neptun Deep gas field in the Black Sea, which will transform the terminal into a key logistics hub for exports and the distribution of natural gas and its derivatives. This development underscores the need for enhanced pollution prevention measures to protect the region's soil and water resources. This study develops an integrated hydrogeophysical model for characterizing the subsurface extent of pollution by correlating advanced geophysical methods with pre-existing hydrogeological and geological data. Based on the geomorphological analysis of the area, magnetometry, electrometry, ground-penetrating radar (GPR), and photogrammetry are applied, alongside seismic refraction, which is used for the first time in this region. The studied area features a coastal landscape dominated by recent sedimentary deposits and complex aquifer structures that influence the dynamics of subsurface pollution. Natural coastal erosion and fluctuations in the water table contribute to increased vulnerability to contamination, necessitating close monitoring of interactions between industrial activities and the geological environment. Magnetometry is employed to detect buried metallic structures, such as historical pipelines that may be fractured and serve as potential pollution sources. Electrometry assesses variations in soil resistivity, enabling the identification of the water table level and sedimentary succession, both critical factors in evaluating pollutant migration potential. Ground-penetrating radar (GPR) provides high-resolution imaging of contaminated areas, while seismic refraction helps identify geological discontinuities that may influence contaminant spread. Aerial photogrammetry supports detailed terrain mapping and long-term pollution monitoring. The correlation of geophysical data with historical borehole records in the area allows for the reconstruction of geological structures and stratigraphic sequences. These data are integrated into the hydrogeophysical model, which estimates the migration pathways of the pollution plume and identifies essential measures for protecting soil and groundwater resources. The study results offer a comprehensive understanding of hydrocarbon dispersion mechanisms in the subsurface and support authorities and industrial operators in making informed decisions regarding pollution risk management. This research demonstrates the applicability of modern geophysical methods in environmental protection and proposes a replicable methodological framework for other industrial areas exposed to contamination risks.

Introduction With the global energy demand on the rise, natural gas plays a crucial role as a clean and efficient energy source. However, wellbore liquid loading has become a key constraint on the stable production of gas fields in their mid-to-late stages—specifically, it affects approximately 40% of the gas wells in the Liaohe Oilfield, leading to productivity declines or even well shut-ins. Foam Assisted Lift (FAL) is a mainstream technical solution to mitigate wellbore liquid loading due to its low cost and strong adaptability. Nevertheless, FAL is plagued by crude design of dosing parameters in practical applications, which either causes unnecessary chemical waste (from overdosing) or results in operational failure (from underdosing), limiting its efficiency and economic viability. Methods This study focused on three typical gas wells (Well Y-1, Y-2, and Y-3) with distinct liquid loading and FAL application statuses: Well Y-1 did not adopt foam drainage technology; Well Y-2 achieved good liquid production after FAL application but suffered from excessive foam drainage agent injection; Well Y-3 used FAL but failed to meet the expected foam drainage target. To address the limitations of traditional FAL parameter design, this research innovatively treated foam as a special type of liquid to align with existing wellbore pressure (e.g., Beggs-Brill method) and temperature distribution models. On this basis, three core technical components were developed: 1) a segmented liquid loading calculation model based on the casing-tubing pressure difference; 2) a comprehensive dosing parameter optimization system covering initial dosage, daily replenishment amount, and injection cycle; and 3) validation of critical liquid-carrying velocity models (including the Turner model, Li Min model, and Wang Yizhong model) to screen the most applicable one for foam systems. Results The optimized FAL scheme yielded significant performance improvements and cost reductions. In terms of liquid-carrying capacity: Well Y-1 (previously without FAL) saw a 26.89% enhancement, and Well Y-3 (with underperforming FAL) saw a 22.64% enhancement. In terms of cost control: the daily dosing amount for Well Y-2 was reduced to 32.3% of the original dosage, and the FAL operation cycle for Well Y-3 was extended from 6 days to 17 days, reducing both chemical consumption and operational frequency. Additional key findings include: 1) the Wang Yizhong model was confirmed to have high engineering applicability for predicting foam liquid-carrying capacity, outperforming the Turner and Li Min models; 2) the SP-7 foaming agent exhibited better foaming and liquid-carrying performance under low-salinity conditions; and 3) concentration of the foaming agent, gas flow rate, and wellbore temperature were identified as key factors significantly influencing the efficacy of SP-7. Discussion This research addresses the core problem of crude dosing parameter design in traditional FAL technology by integrating a segmented liquid loading calculation model and a targeted parameter optimization system. The confirmation of the Wang Yizhong model’s applicability provides a reliable theoretical tool for foam liquid-carrying prediction, while the insights into SP-7’s performance under different conditions offer practical guidance for foaming agent selection in field operations. Overall, this study establishes a technical foundation for efficient, cost-effective foam drainage in liquid-loading gas wells, particularly those in mid-to-late-stage gas fields like the Liaohe Oilfield, and provides a reference for solving similar liquid loading challenges in other gas-producing regions.

Experimental estimation of specific surface area of bazhenov oil shale and factors controlling its increase

This study examines the productive horizon of Miocene deposits in an oil and gas field in the Pannonian Basin (Republic of Serbia). To clarify the features of the geological structure and improve the efficiency of upcoming development of new productive areas while increasing oil recovery from existing parts of the field, the authors of this paper conducted a detailed analysis and synthesis of core data, seismic work materials, testing and the dynamics of production wells. Through conducted studies, the authors detailed the geological features of the field, updated the conceptual model, and proposed additional methods for developing the identified oil and gas reservoirs. Researches also rebuilt the geological model, adjusted the placement of the project well stock and developed a set of geological and technical measures to enhance oil recovery. Furthermore, they forecasted of development indicators. The study identified features of the field’s geological structure that suggest a “mosaic” distribution of filtration and capacitive properties within the established hydrocarbon reservoirs. The localized character of the distribution of productivity and variability of field parameters that influence the success of discovery, efficiency of involvement and development of such hydrocarbon deposits confirms the fractal properties of the geological environment. In conclusion, the authors highlighted the necessity of studying and applying the fractal properties of geological objects during oil and gas exploration.

The H2 generation mechanisms of natural gas in the Sulige gas field, Ordos Basin, China

3D static modeling for identifying the main flow units and heterogeneities in the Abu Madi Reservoir, Baltim Gas Field, Nile Delta, Egypt

ABSTRACT A sequence stratigraphic analysis was conducted in the Srikail Gas Field, situated within the Tripura Uplift in the east-central Bengal Basin, near the Surma Sub-Basin. This study aimed to understand the sedimentary infill behaviour and the distribution of producing and non-producing sands by interpreting Mud Log and Wireline Log Data. Deltaic sands of the Miocene Surma Group were analysed, defining surfaces and systems tracts using Maximum Flooding Surfaces (MFS) as sequence boundaries. Four MFS and five third-order sequences (a to e) were identified. The stratigraphic relationship between this scheme and traditional Surma Group stratigraphy revealed that the Bhuban Formation corresponds to sequences a and b, while the Bokabil Formation correlates with sequences c to e. Producing sands A, B, and C were found in the transition from early to late Lowstand Systems Tract (LST), whereas non-producing sands, including the prominent D sand, were located in the Transgressive Systems Tract (TST). The sequence stratigraphic framework of the Surma Group succession offers valuable guidance for hydrocarbon exploration in the Bengal Basin, particularly in and around the Srikail field, with significant implications for both conventional and unconventional reservoirs.

Evaluation of petroleum system elements and processes in the Risha gas field, eastern Jordan: A comprehensive study

The impedance of the surface layer above hydrocarbons was simulated in the dual-frequency mode with prevalence of the low-frequency component of the probing signal. The resistance components of the surface layer above hydrocarbons, which form a symmetric matrix, were investigated. The dependences of the moduli of the surface layer above hydrocarbons on the concentrations of electrons, ions and frequency of the high-frequency component of the probing signal were determined. The frequency dependences of the impedance moduli of the studied media above the deposits and the influence of the layer permittivity were simulated. Resonance frequencies for the resistance components of the surface layer above hydrocarbons were established, which can serve as a criterion for identifying oil and gas fields. The obtained results for determining the impedance of the surface layer can be recommended for use in geoexploration systems for detecting hydrocarbon deposits and accumulations.