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

This study assessed the potential for storing hydrogen underground in depleted gas fields using Northern California as a case study. We examined how much hydrogen California could produce from the electrolysis of curtailed solar and wind energy. Afterward, we assessed the geological and reservoir properties of fields that could potentially support safe and secure underground hydrogen storage. We applied two stages of a three-stage process to select prospective hydrogen storage sites in depleted gas fields. The first stage of the screening process involved integrating geoscience and environmental factors in order to identify the fields that will not be considered suitable for hydrogen storage. Among 182 depleted and underground gas storage fields in Northern California, 147 were disqualified in the first stage of the assessment. The remaining 35 fields were scored and ranked in stage two based on their potential to maximize hydrogen storage and withdrawal. High-scoring sites for underground hydrogen storage and production included reservoirs with dips between 5° and 15°, reservoir porosity above 20%, reservoir flow capacity above 5000 mDm, and reservoir depths between 430 m and 2400 m. We determined that a total of 203.5 million tonnes of hydrogen could be stored at the ten high-scoring sites. We estimated the potential hydrogen recovery from a hypothetical depleted field in California and evaluated the efficiency of converting the curtailed renewable electricity to hydrogen via electrolysis, storing it in the subsurface, and converting produced hydrogen back to electricity. Based on the results, we determined that depleted gas fields have sufficient underground storage capacity to store hydrogen produced from Northern California's curtailed renewable energy sources. Hydrogen recovery efficiency was estimated to be larger than 75% and was limited by the bottom hole pressure of the withdrawal well, hydrogen mixing with in-situ gas, and hydrogen spreading laterally. This study found that power-to-hydrogen-to-power round-trip efficiency maxed out at 36%. Improvements in hydrogen recovery could increase the round-trip efficiency by 8%, while improvements in electrolyzer efficiency could increase the round-trip efficiency by 33%. • Application of a screening and ranking criteria for UHS to fields in California. • High-scoring sites included reservoirs with dips between 5° and 15°, reservoir porosity above 20%, reservoir flow capacity (i.e. quality) above 5000 mDm, and reservoir depths between 430 m and 2400 m • A total of 203.5 million tonnes of hydrogen could be stored at the ten high-scoring sites with average of 75% recovery. • Power-to-hydrogen-to-power round-trip efficiency maxed out at 36%. • Improvements to round-trip efficiency depended significantly on improving electrolyzer efficiency. [ABSTRACT FROM AUTHOR]

Seasonal underground hydrogen storage (UHS) in porous media provides an as yet untested method for storing surplus renewable energy and balancing our energy demands. This study investigates the technical suitability for UHS in depleted hydrocarbon fields and one deep aquifer site in Taranaki Basin, Aotearoa New Zealand. Prospective sites are assessed using a decision tree approach, providing a "fast-track" method for identifying potential sites, and a decision matrix approach for ranking optimal sites. Based on expert elicitation, the most important factors to consider are storage capacity, reservoir depth, and parameters that affect hydrogen injectivity/withdrawal and containment. Results from both approaches suggest that Paleogene reservoirs from gas (or gas cap) fields provide the best option for demonstrating UHS in Aotearoa New Zealand, and that the country's projected 2050 hydrogen storage demand could be exceeded by developing one or two high ranking sites. Lower priority is assigned to heterolithic and typically finer grained, labile and, clay-rich Miocene oil reservoirs, and to deep aquifers that have no proven hydrocarbon containment. • UHS could provide temporary storage for a large surplus of renewable energy. • The technical feasibility of potential storage sites in Taranaki Basin is assessed. • Two methods for site evaluation are applied, using multi-criteria decision analysis. • Depleted gas fields are considered the best option for demonstrating UHS technology. • The projected 2050 storage capacity demand for NZ could be met by developing 1–2 sites. [ABSTRACT FROM AUTHOR]

Proton exchange membrane fuel cell (PEMFC) has been widely recognized as promising applications of hydrogen energy in automobiles and stationary power generation. Water management in PEMFC is crucial at high current densities, where mass transfer polarization and ohmic losses are the primary factors that limit performance. Both the flow field and the microporous layer (MPL) have a significant impact on water management efficiency. In this study, the researchers investigated the synergistic interaction between the flow field and MPL. Two types of flow fields were carefully examined: a single serpentine flow field and a triple serpentine flow field, along with two different MPL loadings. The water retention and mass transfer properties of various flow fields and MPLs were investigated. The maximum power density of the best combination is 9.86% higher than that of the worst combination, reaching 1.47 W/cm2. It was found that the water management properties of the flow fields and the MPL need to be coordinated to achieve effective water management. The essence of synergistic interaction is to facilitate the balance between ohmic resistance and mass transfer resistance by matching the flow field and the MPL. It is indicated that there is no universal optimal MPL loading, and the optimal MPL loading needs to be determined according to the flow field conditions. This work provides a fundamental overview of the engineering development of electrode assemblies. • The Synergistic interaction depends on gas-liquid transport property of flow fields and gas diffusion layers. • There is no universal optimal microporous layer loading. • The optimal microporous layer loading needs to be determined according to the flow field conditions. • The maximum power density of the best combination is 9.86% higher than that of the worst combination. [ABSTRACT FROM AUTHOR]

A first assessment of the storage resource at European scale for underground hydrogen storage in porous media is presented for the European Union and some neighboring countries (Norway, Türkiye, Ukraine, United Kingdom). The study includes different types of porous media: existing underground gas storages, depleted oil and gas fields, deep saline formations. The storage resources are computed based upon a volumetric analytical approach which accounts for hydrogen physical characteristics (density, viscosity, sweep efficiency and capillary trapping). The computed storage resource is in good agreement with published dynamic storage capacity of deep saline formations in Poland. The extension to the continental scale enables a consistent estimate of the various storage resources. The working storage resources at the European scale are about 8000 TWh among which 37 % are onshore which covers the expected storage requirements. The agreement with previously published working storage capacities for depleted gas fields in the UK continental shelf is quite good at about 2662 TWh. However, at the field level, there might be significant differences linked with the consistency requirements at European scale of this study which estimates the production of oil and gas fields without using the actual field production. Despite its restriction of publicly available data, these results show significant storage resources. The working capacities are not evenly distributed over the continent. However, assuming no competitive usage, the working storage resource would be extremely significant when accounting for onshore and offshore potential. Amongst the different porous media, the underground gas storages present the most interest for conversion to hydrogen underground storage despite their smaller storage resource, 460 TWh, than for depleted gas fields, 5440 TWh for the onshore and offshore. The estimate of working storage resource in deep saline formation is quite low, only 46 TWh as it relies upon traps that were previously characterized. [Display omitted] • First European-wide assessment of the working storage resources for underground hydrogen storage in porous media. • The European working storage resource is circa 8000 TWh. • 67 % of European working storage resource is in depleted gas fields, 6 % in underground gas storages. • 37 % of European working storage resource is onshore. [ABSTRACT FROM AUTHOR]

Indonesia has natural gas reservoirs with high CO 2 content, such as Natuna and Bojonegoro gas fields. Various technologies have been developed, including cryogenic distillation separation technology suitable for application to gas wells with high CO 2 content. Cryogenic distillation separates CO 2 with high purity according to the operating conditions and the CO 2 dew point. Cryogenic distillation was simulated in this study to determine the purity of the CO 2 and to compare the economic potential of each approach. The highest CO 2 purity using CFZ technology is 98.72% in the Natuna, while the highest purity of CH 4 using Pellegrini Distillation technology is 99.95% in the Bojonegoro. Economically, the Natuna and Bojonegoro estimates using the CFZ technology have a lower total annual cost than the Pelegrini distillation. However, CFZ technology has a lower CO 2 capture cost than Pellegrini Distillation technology, 7.9 USD/tonne CO 2 and 10.26 USD/tonne CO 2. In other words, separation using the CFZ technology is more effective for gas fields with higher CO 2. [Display omitted] • Indonesia has two gas fields with high CO 2 content such as Natuna and Bojonegoro. • Cryogenic technology is most economical for gas field with high CO 2 content. • CFZ concept involves the controlled freezing of CO 2 in a specially designed column. • CO 2 capture cost for CFZ lower than Pellegrini Distillation in both gas fields [ABSTRACT FROM AUTHOR]

Underground hydrogen storage (UHS) plays a critical role in ensuring the stability and security of the future clean energy supply. However, the efficiency and reliability of UHS technology depend heavily on the careful and criteria-driven selection of suitable storage sites. This study presents a hybrid multi-criteria decision-making framework integrating the Analytical Hierarchy Process (AHP) and Preference Ranking Organisation Method for Enrichment of Evaluations (PROMETHEE) to identify and select the best hydrogen storage sites among depleted gas reservoirs in the UK. To achieve this, a new set of site selection criteria is proposed in light of the technical and economic aspects of UHS, including location, reservoir rock quality and tectonic characteristics, maximum achievable hydrogen well deliverability rate, working gas capacity, cushion gas volume requirement, distance to future potential hydrogen clusters, and access to intermittent renewable energy sources (RESs). The framework is implemented to rank 71 reservoirs based on their potential and suitability for UHS. Firstly, the reservoirs are thoroughly evaluated for each proposed criterion and then the AHP-PROMETHEE technique is employed to prioritise the criteria and rank the storage sites. The study reveals that the total calculated working gas capacity based on single-well plateau withdrawal rates is around 881 TWh across all evaluated reservoirs. The maximum well deliverability rates for hydrogen withdrawal are found to vary considerably among the sites; however, 22 % are estimated to have deliverability rates exceeding 100 sm3/d, and 63 % are located within a distance of 100 km from a major hydrogen cluster. Moreover, 70 % have access to nearby RESs developments, with an estimated cumulative RESs capacity of approximately 181 GW. The results highlight the efficacy of the proposed multi-criteria site selection framework. The top five highest-ranked sites for UHS based on the evaluated criteria are the Cygnus, Hamilton, Saltfleetby, Corvette, and Hatfield Moors gas fields. The insights provided by this study can contribute to informed decision-making, sustainable development, and the overall progress of future UHS projects within the UK and globally. [Display omitted] • A novel multi-criteria site selection framework is proposed for UHS in gas fields. • Eight selection criteria are proposed to capture the most essential UHS technical and economic aspects. • The model integrates the AHP and PROMETHEE methods for decision-making. • 71 gas reservoirs in the UK are ranked based on their suitability for conversion to UHS assets. [ABSTRACT FROM AUTHOR]

On the path to a net-zero-carbon economy, large-scale energy storage will be an essential part of a renewable energy system. Hydrogen generated from renewable or zero-carbon sources has significant potential as an energy storage medium, by allowing for long-duration and high-capacity energy storage. At the volumes anticipated, however, underground storage systems will likely be essential. Much like the current natural gas system, underground hydrogen storage would provide a safe and cost-effective complement to smaller surface storage infrastructure. Recently, there has been significant interest in the possibility of converting existing gas storage systems to hydrogen storage, though many uncertainties exist in such a process. This paper explores the reservoir dynamics of natural gas/hydrogen gas mixtures and the resulting impacts on storage conversion and gas deliverability. Two specific topics are addressed. First, a novel viscosity model for hydrogen-containing gas mixtures is developed, which shows better agreement with experimental measurements than the widely-used Lohrenz-Bray-Clark model. Second, detailed reservoir simulations are used to investigate cost-effective injection/withdrawal strategies for converting a natural gas storage system to one that stores hydrogen/natural-gas blends. The critical role of buoyancy and gravity override is described, and recommendations are made regarding key reservoir characteristics and injection strategies for managing this behavior. • This study focuses on the conversion of an operational natural gas storage field to hydrogen storage. • A novel viscosity model is developed for hydrogen-containing gas mixtures. • Reservoir simulations evaluate the effect of geologic and engineering parameters on composition and rate of recovered gas. • Gravity segregation significantly influences the severity of fluctuations in the produced gas composition. [ABSTRACT FROM AUTHOR]

This article estimates the potential of using depleted offshore gas fields in Brazil for hydrogen storage and the effects this may have in terms of energy security. Brazil is starting to invest in producing green hydrogen associated with offshore wind energy generation. This initiative has stimulated the search for suitable locations to store hydrogen, including in depleted offshore gas reservoirs. The methodology used in this paper allows for identifying which of the 85 assessed depleted offshore gas fields are the most suitable for hydrogen storage and evaluating the storage capacity of the selected fields. In addition, a wind speed analysis is made to investigate possible locations for prospective wind energy generation projects that can accommodate green hydrogen production. As our main result, we find that the selected depleted offshore gas fields have the potential to store around 5483 TWh worth of hydrogen. This amount is equivalent to about 10 times the total annual electricity consumption in Brazil. Hence, Brazil can comfortably leverage its offshore wind potential in connection with hydrogen production to enhance the energy security of its electricity supply. Considering that to date primarily natural gas has been used as the main source of energy security in Brazil and that its share in the electricity sector has significantly increased over the last decade, the combination of hydrogen storage and renewable energy such as offshore wind power has the potential to provide a resilient and decarbonised electricity system in the country. Furthermore, hydrogen stored in offshore reservoirs in Brazil can become an important resource in the international energy market and constitute a possible key to energy security for countries to which Brazil may export hydrogen. We end our paper by providing comments on the challenges, opportunities, and prospects of offshore hydrogen storage in Brazil. • Offshore natural gas fields in Brazil are suitable for hydrogen storage. • Depleted offshore gas fields can store around 5483 TWh worth of hydrogen. • Two main offshore storage clusters exist in the Southeast and Northeast of Brazil. • Fossil fuel dependence in Brazil can be reduced through hydrogen use and storage. • Large-scale hydrogen storage can contribute to Brazil's energy security. [ABSTRACT FROM AUTHOR]

In this study, the effects of vane channel parameters on the flow field and separator performance are investigated based on a vane type gas-water separator for a PEMFC (proton exchange membrane fuel cell) system. The Eulerian-Eulerian model combines with the Multi-Fluid VOF (volume of fluid) modeling approach is used to comprehensively investigate the gas-liquid two-phase flow field and performance indexes in the separator, and the sensitivity analysis of the structural parameters is carried out. The results show that the pressure drop of the separator gradually increases with the increase of the vane contraction ratio, while the separation efficiency has a tendency to increase and then decrease with the increase of the vane incidence angle. For the separation efficiency, the most beneficial structural variant results in an increase of 11.63%, while for the pressure drop, almost all structural variants result in a reduction of the pressure drop from the standard structure with a maximum reduction of 36.58%. By analyzing the phase distribution, pressure field and velocity distribution of different structures, it can be obtained that the main factors affecting the performance of the separator are the extreme values of tangential velocity inside the separator and the symmetry of velocity distribution in the internal flow field. The results presented in this study can provide a reference for the PEMFC gas-water separator. [Display omitted] • A numerical simulation coupling Eulerian method with Multi-Fluid VOF model is applied. • A new gas-water separator structure for PEMFC system is investigated in detail. • Vane incidence angle and vane contraction ratio have a large effect on separator performance. • Sensitivity analysis of vane structural parameters to find out their priorities. [ABSTRACT FROM AUTHOR]

Coal in a natural geological mass is typically heterogeneous, potentially containing widely distributed faults that affect gas migration and are closely associated with the occurrence of coal-gas outbursts. In this study, the permeabilities of intact and heterogeneous coals during the mining process were described using a dual-porosity model and modified transversely isotropic permeability model, respectively. Numerical simulations based on these models revealed a high gas pressure gradient in front of the working face largely owing to the blocking effect of a low-permeability zone along the fault that led to the formation of a high-pressure gas zone; field measurements confirmed that the gas content in this zone was 2–3 times that in ordinary coal. When close to the fault, a considerable quantity of gas was observed within the working face, then the gas emission increased by 2.4 times once the low-permeability zone along the fault was obliterated. Finally, the proposed model was employed to explain how concurrent increases in shear stress and gas pressure affect the stability of a fault and promote coal-gas outbursts. The proposed model can be applied to conduct theoretical assessments informing measures to prevent gas-related dynamic disasters in coal mines. [ABSTRACT FROM AUTHOR]

Underground hydrogen storage will be an essential part of the future hydrogen infrastructure to provide flexibility and security of supply. Storage in porous reservoirs should complement storage in salt caverns to be able to meet the projected high levels of required storage capacities. To assess its techno-economic feasibility, a case study of hydrogen storage in a depleted gas field in the Netherlands is developed. Subsurface modelling is performed and various surface facility design concepts are investigated to calculate the levelized cost of hydrogen storage (LCOHS). Our base case with hydrogen as cushion gas results in an LCOHS of 0.79 EUR/kg (range of 0.58–1.04 EUR/kg). Increasing the number of full-cycle equivalents from 1 to 6 lowers the storage cost to 0.25 EUR/kg. The investment cost of the cushion gas represents 76% of the total cost. With nitrogen as cushion gas, LCOHS is reduced to 0.49 EUR/kg (range of 0.42–0.56 EUR/kg). [Display omitted] • The Roden gas field is a potential case for seasonal and short-term H2 storage. • A two-stage reciprocating compressor is required to inject H2 into the reservoir. • Pressure Swing Adsorption unit is selected to separate H 2 from gas impurities. • The levelized cost of H 2 storage for the base case is below 1 EUR/kg. • Uncertainty analysis in different cost elements for the levelized cost is studied. [ABSTRACT FROM AUTHOR]

The underground hydrogen storage (UHS) capacities of shut down oil and gas (O&G) fields along the Norwegian continental shelf (NCS) are evaluated based on the publicly available geological and hydrocarbon production data. Thermodynamic equilibrium and geochemical models are used to describe contamination of hydrogen, loss of hydrogen and changes in the mineralogy. The contamination spectrum of black oil fields and retrograde gas fields are remarkably similar. Geochemical models suggest limited reactive mineral phases and meter-scale hydrogen diffusion into the caprock. However, geochemical reactions between residual oil, reservoir brine, host rock and hydrogen are not yet studied in detail. For 23 shut down O&G fields, a theoretical maximum UHS capacity of ca. 642 TWh is estimated. We conclude with Frigg, Nordost Frigg, and Odin as the best-suited shut down fields for UHS, having a maximum UHS capacity of ca. 414 TWh. The estimates require verification by site-specific dynamic reservoir models. • First evaluation of hydrogen storage potential of shut down fields on the Norwegian continental shelf. • Estimate of contamination risks due to residual hydrocarbons and geochemical reactions. • Cumulative maximum theoretical hydrogen storage capacity for 23 shut down oil and gas fields of up to 642 TWh. [ABSTRACT FROM AUTHOR]

Hydrogen storage can help achieve climate change and reduce greenhouse gas emissions. This paper presents a first assessment of the suitability of northeastern Italy for underground hydrogen storage (UHS). The study focuses on the analysis of publicly available well data, which allowed identifying geological formations potentially suitable for UHS. The most promising area, known as the "Treviso Area" consists of both saline aquifers and depleted gas fields. One of the key petrophysical properties, i.e. porosity, was calculated for each of the five wells revealing conditions potentially suitable for UHS by applying empirical formulas to geophysical log data. For the two depleted gas fields, a hydrogen injection simulation was also performed. This work is a pioneer study and lays the foundation for hopeful further analyses, which could help implement the recently launched "North Adriatic Hydrogen Valley" initiative. [Display omitted] • A first assessment of underground hydrogen storage (UHS) in Italy is provided. • In NE Italy, saline aquifers and depleted gas fields are potentially suitable for UHS. • A key petrophysical property for UHS, porosity, is calculated from geophysical logs. • A simulation of hydrogen injection and production is provided. [ABSTRACT FROM AUTHOR]

Hydrogen is becoming an alternative for conventional energy sources due to absence of any Greenhouse Gases (GHG) emissions during its usage. Geological storage of hydrogen will be potential solution for dealing with large volume requirement to manage uninterrupted Hydrogen supply-chain. Geological Storages such as depleted reservoirs, aquifers and salt caverns offer great potential option for underground hydrogen storage (UHS). There are several depleted gas fields in India. One of such field is located in Tapti-Daman formation. A comprehensive study is conducted to assess the possibility of hydrogen storage in this Indian field which is first of its kind. The geological characteristic of this site is assessed for its viability for storage. Additionally, several aspects including storage capacity, sealability, chemical and micro-biological stability, reservoir simulation, and production viability are assessed using various analytical and numerical models. The qualitative analysis of the Tapti-gas field suggests that the integrity of the storage site will be intact due to existing anticlinal four-way closed structure. The chemical and micro-biological losses are minimal and will not lead to major loss of hydrogen over time. The reservoir modeling results show that optimum gas production-injection scheme needs to be engineered to maintain the required reservoir pressure level in the Tapti-gas field. Also, the deliverability of the various seasonal storage time show that 80 days production scheme will be suitable for efficient operation in this field. Finally, a synergistic scheme to enable green energy production, storage, and transportation is proposed via implementation of UHS in the offshore Tapti-gas field. • Holistic investigation of combined reservoir and geochemical modeling required for assessing the feasiblility of UHS. • Injection and production scheduling is required for better utilization of seasonal hydrogen storage and production. • Out of detrital and authigenic components, detrital component has significant impact on geochemical inverstigation. • Production and injection rate impacts reservoir pressure. • First prospect study for Offshore Indian depleted gas field for UHS purpose. [ABSTRACT FROM AUTHOR]

Underground hydrogen storage (UHS) in depleted hydrocarbon reservoirs is a prospective choice to store enormous volumes of hydrogen (H 2). However, these subsurface formations must be able not only to store H 2 in an effective and secure manner, but also to produce the required volumes of H 2 upon demand. This paper first reviews the critical parameters to be considered for geological analysis and reservoir engineering evaluation of UHS. The formation depth, the interactions of rock-brine-H 2 , the caprock (seal) and well integrity are the most prominent parameters as far as UHS is concerned. In respect of these critical parameters, tentative H 2 storage is screened from the existing gas storage fields in the Niigata prefecture of Japan, and it was revealed that the Sekihara gas field is a suitable candidate for UHS with a storage capacity of 2.06 × 108 m3 and a depth of 1000 m. Then, a series of numerical simulations utilizing CMG software was conducted to find out the extent to which critical parameters alter H 2 storage capacity. The results demonstrated that this field, with a recovery factor of 82.7% in the sixth cycle of production is a prospective site for H 2 storage. [Display omitted] • Niigata prefecture in Japan has a good potential for underground H 2 storage. • Sekihara, Kumoide, and Katakai fields are the top candidates for storage of H 2. • A comprehensive review of crucial parameters for the underground H 2 storage is provided. • Effect of the crucial parameters studied using CMG software in the Sekihara field. • Reservoir simulation proved the feasibility of H 2 storage in the Sekihara field. [ABSTRACT FROM AUTHOR]

Multi-Gas source localization and mapping is a challenging problem because multiple measurements must be taken to ensure accurate localization. This paper presents a novel flocking control strategy for multi-robot exploration and gas field mapping to address this problem. The algorithm includes an active sensing mechanism for driving a flock of agents towards target measurement locations that optimize the posterior probability density and a collaborative sequential Monte Carlo information fusion approach for estimating gas fields. We tested the performance of our system on Jackal mobile robots in a chemical leak scenario with two gas leakage sources. Through a series of comparison experiments, we demonstrate that our proposed strategy has superior performance to recent single-agent and centralized sequential Monte Carlo-based gas concentration mapping in terms of the estimate accuracy, the convergence time, and the mapping error. • Present a collaborative Sequential Monte Carlo method for estimating gas fields. • Propose a flocking model to keep the robots close enough to avoid disconnections. • Include an active sensing method for moving a robot swarm towards measurement locations. • Construct an evaluation of our algorithm in a setting with multiple leakage plumes. • Conduct a comparative study benchmarking our algorithm against other strategies. [ABSTRACT FROM AUTHOR]

• A model was developed to simulate hydrate formation in porous media. • The model was validated using experimental data. • Injection of cold CO 2 into depleted gas fields was simulated. • The impact of water evaporation on hydrate formation was studied. The reduction of temperature caused by Joule-Thomson effect during injection of CO 2 in low pressure reservoirs combined with presence of water can lead to formation of hydrates, which in turn reduces rock permeability and hence CO 2 injectivity. This paper introduces an empirical model to evaluate impact of hydrate formation on injectivity of CO 2 injection wells. Experiments were also conducted to validate the model. The model was then used to simulate injection of CO 2 into a multi-layered depleted gas field. The results indicate that operational parameters, particularly CO 2 injection rate and temperature, have a large influence on hydrate formation. This is because a higher CO 2 injection rate leads to a greater pressure drop within the injection well, potentially triggering conditions conducive to hydrate formation. It is also shown that the dynamics of the competition between the dry-out and temperature fronts play an important role in the final saturation of the hydrate within porous media. For large evaporation rates, the evaporation of water reduces water saturation near wellbore and hence formation of hydrates is limited. [ABSTRACT FROM AUTHOR]

The fan delta front deposit is a notable reservoir type in the basin margin and typically exhibits high heterogeneity in reservoir architecture. With the deepening of exploration and development of oil and gas fields, the study of lower-order depositional architectures is relatively weak, and their implication on remaining oil distribution and enrichment are poorly understood. Field outcrops of the fan delta front deposit exhibit first-hand data of lithofacies, association, and depositional architectures, effectively providing insights for underground reservoir research to guide the development of oil fields, such as high water–cut oil fields in the late development period. Herein, we considered the fan delta front outcrops of the Sangyuan section as an object to reveal the depositional architectures located in the Luanping Basin, northeast China. Using meticulous artificial fieldwork and unmanned aerial vehicle observation, we focused on the 4th-order (single sandbody) and 3rd-order (composite laminaset groups) architectural units. Based on field observations, quantitative statistics, and model matching and guidance, architectural models of the fan delta front in the Sangyuan section were established in response to the high-frequency lake-level. In addition, genetic types of remaining oil controlled by architectural features in Wenchang B oil field during the high water–cut stage were further discussed, and suitable strategies and measures are proposed to produce different types of remaining oil. Results indicate that there are twelve basic types of lithofacies and three types of a single sandbody developed in the Sangyuan section, and evidently, the dimensions and spatial stacking patterns of 4th-order architectural units are closely related to high-frequency lake-level fluctuation, that is, with the rise of lake-level, the thickness and width of a single sandbody gradually decrease, whereas the width–thickness ratio gradually increases. Meanwhile, the spatial stacking patterns of sandbody gradually evolution from the downcut type to the superposition or butted type and finally to the isolated type. A single sandbody is divided into one or more composite laminate groups by the interfaces of 3rd-order architectural elements, which are identified according to the flow regime and sedimentary structures. Different orders of architectural units have different controlling effects over remaining oil distribution and enrichment, and the corresponding technical measures are proposed to enhance the remaining oil recovery. The above mentioned analyses can provide a valuable reference for oil and gas production in the late stage of an oil field with a similar depositional environment. • Representative lithofacies types, sedimentary structures, and lithofacies association of fan delta front deposits were examined and identified. • Single sandbody and their internal component units of fan delta front deposits are identified and characterized in detail. • The controlling effect of high-frequency lake level fluctuation on architecture features was determined. • Architectural model helps solve the production problems and enhance the remaining oil recovery during the high water cut stage of oil field development with a similar depositional environment. [ABSTRACT FROM AUTHOR]

Liquefied natural gas (LNG) plays a primary role in long-distance transportation; however, its production is energy-intensive, and CO 2 emissions from its use are unavoidable. To address these challenges, a liquid CO 2 -mixed refrigerant (LCO 2 MR) process is proposed, utilizing CO 2 in two distinct ways: (i) recovering cold energy from LNG regasification for use in the natural gas liquefaction process and (ii) injecting CO 2 into gas fields for enhanced gas recovery (EGR), boosting natural gas production. This study comprehensively analyzes the proposed process, focusing on thermodynamic, economic, and environmental impacts. The energy consumptions for the propane precooled mixed refrigerant (C3MR) and LCO 2 MR processes are 970 and 815 kJ/kg of LNG, respectively. The LCO 2 MR process has an annual expense 18.94 % lower than C3MR process when considering carbon tax, due to its simpler structure and lower energy requirements. Environmentally, the LCO 2 MR process reduces CO 2 emissions by 53.33 % across the value chain compared to the C3MR process. Additionally, using CO 2 for EGR is projected to increase natural gas production by 81.67 tons/h. These results indicate that utilizing CO 2 as a cold energy carrier and for increasing natural gas production is energetically and economically advantageous, significantly reducing CO 2 emissions and contributing to a cleaner LNG value chain. [Display omitted] • LCO 2 is produced by recovering LNG cold energy and used for LNG production. • Vaporized CO 2 is injected into gas fields for enhanced gas recovery. • Using LCO 2 , the SEC of NG liquefaction decreases by 15.98 % compared to C3MR. • Annual expense of LCO 2 MR process is 18.94 % lower than C3MR due to its simplicity. • The proposed design can reduce CO 2 emissions by 53.33 %. [ABSTRACT FROM AUTHOR]

[Display omitted] • Quaternary phosphonium-polyamide NF membranes are prepared. • The membrane rejection for MgCl 2 reaches 98.9 % with a water flux of ∼50 LMH. • The Mg2+/Li+ selectivity of 81.6 exhibits notable competitive advantages. • The membranes exhibit superior anti-fouling and anti-bacterial characteristics. • The preparation method is simple and scalable for continuous production processes. Lithium extraction from brine sources such as salt lakes, seawater, and produced water from oil/gas fields is garnering increasing interests from the academic and industrial sectors due to its cost-effectiveness and reduced environmental impact. A critical technological challenge is the efficient separation of Mg2+ and Li+ ions. Many researchers have reported the preparation of positively charged nanofiltration membranes with quaternary ammonium groups, yet investigations about quaternary phosphonium groups are scarce. In this work, positively charged nanofiltration membranes were prepared utilizing polyethyleneimine as the aqueous phase monomer, trimesoyl chloride as the organic phase monomer, and 3-bromopropyl triphenyl phosphonium bromide as the functionalizing monomer. The TFC-P+ membranes, enriched with a high density of quaternary phosphonium groups and an enhanced Donnan effect, achieve a MgCl 2 rejection of 98.9 %, a Mg2+/Li+ selectivity of 81.6, and a water flux of 50 LMH under 0.5 MPa. The membranes possess an enhanced comprehensive separation capability that exceeds that of the majority of nanofiltration membranes documented in scholarly articles. Additionally, the membranes exhibit outstanding anti-fouling and anti-bacterial characteristics, essential for their industrial applications. The preparation method proposed herein is simple and conducive to continuous production processes. In light of the abundant produced water reserves from oil and gas extraction, future work will focus on pilot-scale lithium extraction experiments. [ABSTRACT FROM AUTHOR]

Depleted oil and gas fields constitute potentially important storage sites for CO 2 in the subsurface, but large-scale injection of supercritical (sc) CO 2 in chalk has not yet been attempted. One of the risks is the adverse effect of the substantial amount of remaining oil in the chalk reservoirs on scCO 2 injection. In order to counter an undesired effect on injectivity, a fundamental understanding of the spatial distribution and quantity of the movable, semi-movable, and non-movable oil, and solid bitumen/asphaltenes fractions of the remaining oil is critical. In this study a combination of organic geochemistry (gas chromatography of the saturated fraction and programmed pyrolysis), and reflected light microscopy was applied to evaluate and measure the spatial distribution, volume, and saturation of different oil fractions in a well-defined reservoir interval of a waterflooded Maastrichtian chalk reservoir in the Danish Central Graben, North Sea. A total of 127 samples from a slightly deviated vertical well and two ∼5 km-long horizontal wells from the Halfdan and Dan fields were analyzed. An original uneven distribution of oil saturation and composition or different production efficiency of different levels in the reservoir may account for variations in the total oil and oil fraction saturations. Gas chromatography shows that the solvent extractable oil is quite similar in composition, characterized by a dominance of polar compounds and a high content of asphaltenes. Extended slow heating (ESH) pyrolysis reveals that most of the remaining oil saturation consists of semi-movable oil and total non-movable oil (non-movable oil plus solid bitumen/asphaltenes). Reduced oil gravity values (API) are related to evaporation loss of the lightest hydrocarbon fraction during core storage and increase of the relative proportion of the heavier oil fractions by waterflooding during production. Microscopy disclosed three forms of oil: i) Patchy distributed lighter, movable oil showing a bluish fluorescence, ii) Brownish staining with a dark orange to brownish fluorescence, and iii) Dark brown non-fluorescing oil and black solid bitumen/asphaltenes occurring in microfossils and along deformation bands and stylolites, constituting the heavy non-movable oil fractions. There is a general correlation between bulk rock porosity and the total non-movable oil saturation. It thus appears that the heavy non-movable oil fractions preferentially occur in association with low-permeability heterogeneities within high-permeability stratigraphic intervals. These intervals appear to favor accumulation of non-movable oil and solid bitumen/asphaltenes and may carry a higher risk for impeding scCO 2 flow. • The saturation of different oil fractions were quantified in a chalk reservoir. • Saturation of total non-movable oil includes solid bitumen/asphaltenes. • Semi-movable and total non-movable oil dominate the remaining oil. • Solid bitumen/asphaltenes in deformation bands and stylolites coincide with high porosity. • The semi- and non-movable oil fractions may pose a risk for scCO 2 injection. [ABSTRACT FROM AUTHOR]

• Five petrofacies are classified to reveal controls on diagenesis and reservoir quality. • Different petrofacies experienced contrasting diagenetic and porosity evolutions. • Diagenetic events are assigned as pre- and post-petroleum, petroleum-stage events. • Petrofacies-A and −C had moderate porosity and were charged during peak gas migration. Reservoir quality of, and gas production rates from, tight sandstones in the Lower Permian Shanxi Formation vary greatly across the Yan'an Gas Field, southeastern Ordos Basin, China. Effective reservoirs are significant for the economic success of tight gas exploration and production. This study examined the relationships between diagenetic evolution, porosity reduction and hydrocarbon charge to reveal the formation and distribution of effective reservoirs in this field. The sandstones are very fine- to coarse-grained, quartz arenites, sub-litharenites and litharenites. The significant variations in the texture and mineralogical composition of the sandstones exert major controls on diagenetic heterogeneity and pore distribution. Five petrofacies (petrofacies-A to -E) are classified. The various petrofacies experienced contrasting diagenetic evolution and petroleum charge histories. The medium- to coarse-grained, quartz arenites (petrofacies-A) and sub-litharenites (petrofacies-C) experienced less ductile compaction and cementation and extensive grain dissolution, and remained relatively porous before early hydrocarbon emplacement. When peak gas generation and migration occurred, petrofacies-A and -C still had moderate porosity and were able to be charged. On the contrary, the fine-grained, tuffaceous quartz arenites (petrofacies-B), ductile grain-rich sandstones (petrofacies-D) and tightly carbonate-cemented sandstones (petrofacies-E) experienced limited diagenetic alterations with ductile compaction or carbonate cementation predominating and leading to extensive loss of porosity during eodiagenesis. Petrofacies-B, -D and -E had low porosity before early petroleum charge. Petrofacies-A and -C therefore constitute the only effective reservoir rocks of tight reservoirs of the Shanxi Formation. This study indicates that petrofacies is useful for reservoir characterization and modeling in the Yan'an Gas Field and other tight gas fields worldwide. [ABSTRACT FROM AUTHOR]

Hydrogen has attracted attention worldwide with its favourable inherent properties to contribute towards a carbon-free green energy future. Australia aims to make hydrogen as its next major export component to economize the growing global demand for hydrogen. Cost-effective and safe large-scale hydrogen storage in subsurface geology can assist Australia in meeting the projected domestic and export targets. This article discusses the available subsurface storage options in detail by first presenting the projected demand for hydrogen storage. Australia has many subsurface formations, such as depleted gas fields, salt caverns, aquifers, coal seams and abandoned underground mines, which can contribute to underground hydrogen storage. The article presents basin-wide geological information on the storage structures, the technical challenges, and the factors to consider during site selection. With the experience and knowledge Australia has in utilizing depleted reservoirs for gas storage and carbon capture and sequestration, Australia can benefit from the depleted gas reservoirs in developing hydrogen energy infrastructure. The lack of experience and knowledge associated with other geostructures favours the utilization of underground gas storage sites for the storage of hydrogen during the initial stages of the shift towards hydrogen energy. The article also provides future directions to address the identified important knowledge gaps to utilize the subsurface geology for hydrogen storage successfully. • Australia's hydrogen storage demand is discussed. • Different underground hydrogen storage options and their geologic information are provided. • Technical challenges associated with underground hydrogen storage are discussed. • Factors to consider during storage site selection are presented. [ABSTRACT FROM AUTHOR]

The failures of drilling operation in oil and gas fields may cause big economic losses owing to several technical consequences such as safety incidents, machinery damages, environmental impacts, etc. To prevent unwelcome events in drilling activities, it is necessary to assess and reduce the potential related risk factors. Hence, the present paper offers a framework to diagnose and analyze drilling operation risk factors in one of the Iranian gas field, located in the south area of the country. The proposed methodology consists of four main stages: providing knowledge sources, risk identification, general risk analysis, and estimation of wellbores overall risks. This framework helps to ensure the successfully performance of drilling companies, and to access safety standards. An improved version of the FMEA method (Failure Mode and Effects Analysis), named as modified FMEA, is suggested by adding risk controllability criterion. Further, a generalized version of the ROC method (Rank Order Centroid) is developed. This method is used to estimate the weights of any ranked entities. Moreover, a new idea called VIMUN (Vital, Important, Medium, Unimportant, and Negligible) is proposed to deal with weighting problems when there are many number of entities to be weighted. A hybrid of the modified FMEA, GROC, and VIMUN methods is used for evaluating the risk factors in the field, and for determining the level of overall risk of each wellbore. The results show that the lost circulation of drilling fluid caused by high density of natural fractures in formation, and lack of advanced technology has the highest priority, and is the most serious failure in drilling operation in the field under study. The failures at the next ranks are drilling rig fire & explosion, well blowout, and wellbore instability. Using the proposed methodology, 36 wellbores in the field are grouped into five classes according to their levels of risk. The robustness of the results was confirmed by carrying out a sensitivity analysis. [ABSTRACT FROM AUTHOR]

The plunger lift is one of the main methods to release liquid loading in gas wells. Due to the leakage in the process of moving for plunger, the efficiency of liquid unloading is decreased. In recent years, the single flowing plunger was invented and has been used in many gas fields. However, the mechanism of enhanced liquid unloading is still unclear. In this paper, a full-size visible plunger lift equipment was built to study the process of single flowing plunger lift (SFPL) and normal plunger lift (NPL). Moreover, a transient model was built to simulate SFPL and NPL in different situation. Results show that the SFPL can prevent the liquid from dropping, decrease the bottom-hole pressure, and enhance gas production. The SFPL performs well in a certain range, and the SFPL would be out of operation first. A plate has been built to help engineers optimize the SFPL. The paper helps clear the situation of SFPL and provides the theoretical basis for researchers. • A full-size visualized plunger lift equipment and a transient numerical model were built. • The mechanism of liquid unloading for the single flowing plunger was revealed. • Applied range of single flowing plunger was cleared. [ABSTRACT FROM AUTHOR]

The offshore region of East Africa has undergone extensive geological evolution since the Permian period, characterized by two stages of rifting phases followed by a subsequent stage of passive margin development. The stratigraphic record in this area is comprehensive, indicating the formation of multiple series of source rocks. Recent discoveries have identified over 200 trillion cubic feet of natural gas in the Ruvuma Basin, in addition to a modest quantity of light crude oil found onshore in Mozambique. However, the precise origins of hydrocarbons in this region remain unclear. In this study, the paleo-position restoration technique for oil and gas fields was utilized to reconstruct the paleo-positions of key wells and reservoirs during critical periods of source rock development. Three significant Deep Sea Drilling Project (DSDP) and Ocean Drilling Program (ODP) wells drilled in the offshore region of East Africa were selected for source rock assessment. The geochemical data obtained from these wells were systematically analyzed, resulting in the creation of continuous geochemical profiles that elucidate the characteristics of the thick, high-quality, oil-prone marine source rocks formed in the southern offshore region of East Africa during the Upper Jurassic to Lower Cretaceous periods. These source rocks exhibit high total organic carbon (TOC) and hydrogen index (HI) values, indicating a robust capacity for hydrocarbon generation. They are widely distributed and predominantly consist of oil-prone Type II1-II2 kerogen. The sequence of source rocks with elevated TOC exceeds 115 m in thickness. Carbon isotope data from methane and ethane in natural gas samples suggest that the hydrocarbons in the onshore and southern offshore areas of East Africa are derived from these Upper Jurassic to Lower Cretaceous marine source rocks, thereby indirectly indicating significant exploration potential for these source rocks. Based on seismic sections, a hydrocarbon accumulation model has been developed for the southern offshore region of East Africa. This model comprises multiple series of source rocks that provide sufficient hydrocarbon supply, effective source-reservoir-seal assemblages, and near-source hydrocarbon migration and accumulation. The findings of this study enhance confidence in hydrocarbon exploration within the study area and further delineate potential areas and directions for future exploration efforts. • Use the technique of paleo-positions reconstructing to restore four key DSDP/ODP wells to the key period of source rock. • Established geochemical profiles and isochronous stratigraphic frameworks for 4 key DSDP/ODP wells. • Confirmed the development of oil prone high-quality hydrocarbon source rocks of the Upper Jurassic-Lower Cretaceous in the southern offshore of East Africa. • Established an oil and gas accumulation model and clarified the exploration potential of the East African offshore. [ABSTRACT FROM AUTHOR]

In the region of large gas fields, extensive research has been conducted on earthquakes induced by industrial production in shale gas fields. However, limited attention has been given to the impact of post-earthquake events on shale gas reservoir leakage and fault activation. The Luxian M S 6.0 earthquake, which occurred on 16 September 2021 in the Luzhou shale gas field, has raised concerns about post-earthquake shale gas leakage. Post-earthquake measurements of soil gases (Rn, CO 2 , CH 4 , and H 2) and isotopic analyses (δ13C CO2 , δ13C CH4 and δD CH4) in the Luzhou shale gas field area reveal that the Huayingshan fault zone, a natural pathway for shale gas leakage, was not activated by the Luxian earthquake and did not exhibit any further shale gas leakage after the 2021 earthquake. Furthermore, the seismogenic fault, which was impacted by the earthquake, did not damage the shale gas reservoir, causing shale gas leakage. This study provides an important foundation for future research on shale gas extraction and seismic activity in the region. • Shale gas extraction induced earthquakes may not cause large-scale methane leaks. • The seismogenic fault, which was ruptured by the Luxian earthquake, did not result in shale gas leakage. • Induced earthquakes will not cause additional large-scale leaks from existing active faults in the surrounding area. • The occurrence of Luxian earthquake was induced by long-term wastewater injection and short-term hydraulic fracturing. [ABSTRACT FROM AUTHOR]

The trade of resources geographically bridges production and consumption, driving telecoupling between resource extraction and distant consumption. However, the telecoupling between employment and fossil fuels has not been quantitatively analyzed yet, presenting a barrier to employment management under the energy transition away from fossil fuels. Here we investigate the telecoupled employment driven by intercity fossil fuel trade in China. A spatially explicit inventory of 989 coal mines, 642 oil fields, and 461 gas fields has been compiled for analysis. The results show that 1560 k of workers extract fossil fuels to satisfy external energy demands (referred to as telecoupled employment), accounting for 70 % of total employment for fossil fuel extraction in China. The coal trade drives 58 % of the total telecoupled employment while oil and gas drive 42 %. 26 % of intercity telecoupled employment is transferred intra-provincially whereas 74 % is transferred interprovincially. 222 cities drive more employment from the consumption-based perspective than from the production-based perspective, while 91 cities see the reverse. It is of significance for fossil fuel exporters to incorporate this telecoupling (e.g. the direction and scale of telecoupled employment) into city policies to assess the transboundary employment impacts of the changes in energy demands of importers. • Telecoupling between employment and fossil fuels is assessed at the city level. • Telecoupled employment amounts to 70 % of total fossil-fuel employment. • 74 % of intercity telecoupled employment is transferred interprovincially. • Domestic final demand drives 84 % of telecoupled employment. [ABSTRACT FROM AUTHOR]

Super 13Cr martensitic stainless steel (UNS S41426, S13Cr MSS in the case) developed for gas fields is being applied more broadly. However, the stress corrosion cracking induced by pitting limits its application range. To enhance the corrosion resistance, a new amorphous film was pre-formed on its surface by a modified alkaline solution. The nanoscale amorphous film contained FeO, Fe 2 O 3 , Cr 2 O 3 and Cr(OH) 3 , growing logarithmically after a short dissolution duration. The general corrosion resistance of S13Cr MSS improved significantly, as evidenced by a decrease in corrosion current density by an order of magnitude. Additionally, the pitting potential of S13Cr MSS increased by nearly 100 %. This work provides a strategy for addressing surface defects in S13Cr MSS. • The surface-homogenization idea is developed to improve 13Cr's corrosion resistance. • A nanoscale amorphous film is preformed on surface of 13Cr by a modified solution. • The amorphous film grows logarithmically with production duration. [ABSTRACT FROM AUTHOR]

The Middle Miocene Balikpapan Formation is exposed in the Samarinda Anticlinorium, which forms part of the Lower Kutai Basin situated on East Kalimantan, Indonesia. The Balikpapan Formation is considered the main source rock for oil and gas fields in Lower Kutai Basin. This study integrates sedimentology, organic geochemistry, organic petrography and calcareous nannofossil analysis to characterize the depositional environment, to determine the source of the organic matter, and to assess the hydrocarbon potential of the Balikpapan Formation. The studied sections contain at one locality calcareous nannofossil assemblages with low diversity including Sphenolithus heteromorphus , suggesting nannofossil zones NN4 – NN5 (upper Burdigalian - Langhian-lower Serravallian) are restricted to the Air Putih section in the northeastern part of the study area. Six facies associations were identified in the study area, comprising eleven lithofacies, interpreted as fluvial-deltaic to shallow marine in origin. The fine-grained lithofacies include shale, coaly shale and coal while the coarse-grained facies include sandstone and sandy conglomerates. The geochemical results (TOC) indicate that the analyzed samples have strongly varying total organic carbon (TOC) contents. The organic matter is composed of type III (gas-prone) and type II-III (mixed oil and gas prone) kerogen, with HI values ranging from 32 to 252 mg HC/g TOC. The Rock-Eval parameter T max 409–441 °C and vitrinite reflectance values (0.40–0.67 %Rr) indicate that the sediments are immature to marginal mature. The rank of coal in the Balikpapan Formation ranges from the sub-bituminous to the high-volatile bituminous B stage. • Fluvio-deltaic to shallow marine depositional environment during the Middle Miocene. • Sphenolithus heteromorphus yielded upper Burdigalian-lower Serravallian age. • Coal formed on delta plain in ombrotrophic and marine influenced eutrophic mires. • Thermal maturity stage of the organic matter ranges from immature to early mature. [ABSTRACT FROM AUTHOR]

To optimize production strategy, monitor reservoir performance, and maximize economic recovery of oil and gas fields, it is very important to accurately measure the separate phase flow of each fluid in multiphase flow. Due to the complexity of multiphase flow, the traditional method of measuring the flow per phase is challenging. The Spinner Array Tool (SAT) and equidistant area-weighted average method are used to predict the average fluid velocity of oil-water two-phase flow in horizontal wells. The slippage model is used to calculate the total volume flow of the fluid and the volume flow of each fluid. We collected mini-spinner sensing data in a Spinner Array Tool (SAT) for the oil-water two-phase and used the response characteristics of the single-phase fluid as reference data before mixing. The experimental results show that the isometric area-weighted average method can better process the sensor data of the Spinner Array Tool (SAT), and obtain better phase separation flow accuracy under different flow conditions. The predicted oil flow is in good agreement with the measured oil flow. The results show that it is feasible to infer the prediction results of the fractional flowrate from the prediction results of the average fluid velocity in the actual production logging. • The equidistant area weighted average method was used to predict the flow rate of oil-water two-phase in horizontal wells. • Spinner Array Tool (SAT) was used to collect sensing data of oil-water two-phase mini-spinners. • The predicted oil flow rate is in good agreement with the measured oil flow. [ABSTRACT FROM AUTHOR]

• The rotary thread demister was designed. • The feasibility of the demister was verified through theory and experiment. • Realizable k-ε turbulence model was preferred. • Adopted CFD modelling method to study the changing law of influencing factors. • The parameters of the demister were optimized by RSM and NSGA-II algorithm. To address the clogging of demister by elemental sulfur of high-sulfur gas fields, a rotary thread demister was proposed as an alternate. The results show: The feasibility of the rotary thread demister is verified through force analysis and simulation experiments; The experimental results revealed the Realizable k-ε turbulence model has the smallest average error of 3 %; Increases in rotational speed, count, diameter, and layers of the rotary thread enhance separation efficiency and pressure drop; Higher inlet velocities reduce separation efficiency while increasing pressure drop; Based on the response surface methodology and NSGA-II algorithm, the optimal parameters are determined, achieving separation efficiency of 100 % and pressure drop of 45.67 Pa for 19 μm sulfur particles and 20 μm droplets; The same parameters can remove the 3 μm size droplets and sulphur particles with separation efficiencies of 90.2 % and 92.3 %, respectively, at a pressure drop of 43.8 Pa without considering particle collisions. [ABSTRACT FROM AUTHOR]

Helium is extensively utilized in aerospace, healthcare, electronics, semiconductors, advanced science, and renewable energy sectors, playing a pivotal role in the advancement of human technology. Presently, helium is primarily extracted from natural gas as an associated resource. The cost of extraction decreases with an increase in the helium concentration within the gases. Therefore, understanding the mechanisms involved in helium generation, migration, and accumulation underground is vital. This article delves into the differential enrichment mechanism of helium in the Jinqiu gas field, situated in the Sichuan Basin of China, by analyzing the molecular and isotopic composition characteristics of the major gases and noble gases, employing gas dissolution and diffusion models. Compared with other Jurassic gas reservoirs in the Sichuan Basin, the Jinqiu gas field contains a significantly higher helium concentration, displaying unique enrichment patterns within its area. The majority of hydrocarbon gases originate from the local underlying Triassic Xujiahe Formation source rocks. Specifically, the western section of the Jinqiu field is primarily supplied by the higher maturity Xujiahe Formation source rocks located in the western Sichuan Basin. Notably, there is no significant contribution of mantle-derived volatile components in the Jinqiu field. Helium and argon are primarily radiogenic, whereas neon primarily originates from atmosphere. The good linear correlation between 4He and 20Ne suggests that their transfer is primarily facilitated through groundwater. The solubility calculation reveals that the helium exsolved from the in-situ pore water of the reservoir, due to stratigraphic uplift during the Himalayan movement, comprises only 0.04%–0.11% of the existing reserves. This suggests that gas desolvation plays a relatively minor role in helium enrichment in the Jinqiu field. Additionally, the calculation results of gas diffusion indicate that diffusion's contribution to helium enrichment in the Jinqiu gas field remains minimal. Finally, our analysis of methane reserve changes suggests that the combined effect of differential loss and dilution of hydrocarbon gases is the primary mechanism for helium's differential enrichment in the Jinqiu field. Notably, methane and carbon dioxide depletion may be a significant factor in helium enrichment within the crustal natural gas system. • Differential loss and dilution jointly cause helium enrichment. • Depletion of CH 4 and CO 2 is important enrichment mechanisms of helium. • Low pressure is a key geological condition for helium-rich gas fields. [ABSTRACT FROM AUTHOR]

The use of expansive pipeline networks guarantees domestic and industrial users for accessing a continuous flow of valuable liquids and gases. These pipeline systems were considered the most economical and safest pipeline of transport for oil and gas and are of great strategic importance. The risks during operating conditions need to be controlled to handle the pipeline safely and smoothly in the complex globalized economy. Accordingly, life prediction is an essential issue in the pipeline network of the maintenance systems. Recently proposed data-driven and statistical approaches for pipeline's life prediction continue to rely on previous information to create health indicators and define thresholds, which is inefficient in the significant data era. Thus, a recurrent neural network (RNN)-based method for predicting the life of equipment with corrosion dimension classes exposed to critical condition monitoring is proposed in this research. The RNN model uses the multiple condition monitoring observations at the current and previous inspection points as its inputs and the pipe life condition and corrosion type as its outputs. Further, to improve the predictability of the proposed model, a validation mechanism is introduced during the training process. The proposed RNN method is validated using the data from oil and gas fields that have been collected in real-time. A critical sensitivity analysis with missing parameters is performed to evaluate the model's effectiveness in forecasting the life situation when inputs are absent. A comparative study is also carried out between the proposed RNN method and an adapted version of the reported method. The results show the advantage of the proposed method in achieving an actual life expectancy which can reduce the annual maintenance costs and help take necessary actions for better protection and safety of a pipeline. [ABSTRACT FROM AUTHOR]

• Officials tout possibilities of private contracts to produce gas resources. • Mexican stakeholders show disconnect between access and contract rights. • Contract signatories use contracts for own ends, not for largescale gas production. • Examining contract form and function is a fruitful research agenda for geographers. We examine how contracts mediate private industry access to state-owned subterranean resources. Using a case study from one of Mexico's most productive onshore natural gas fields, the Burgos Basin, we link contract literatures in geography and critical legal scholarship to answer the following two questions: Does the contract text correspond to how private companies access state-owned subsurface resources, and what purposes do the contracts serve for the contract signatories beyond resource production? The data suggest that contract winners have, so far, limited their drilling activities on the Burgos Basin. This situation draws attention to a puzzle wherein natural gas reserves are not being produced, but the contracts remain active and important to both the contractors and the government. Putting semi-structured interview data into direct conversation with contract text to answer our research questions, we encourage a deeper engagement with how extractive contracts are used to access state-owned resources. First, we uncover how the contract text is not instructive of how or why a private firm will access the resource or why the state enters the contract. Second, we highlight the ways that the contract fails to actualize resource production using a mechanisms of access approach to guide our analysis. Third, we show that resource contracts facilitate relationships and advance the interests of the contract parties regardless of what the actual text purports to do. We finally describe how state-firm resource contracts offer a fruitful area of exploration for geographers interested in resource production. [ABSTRACT FROM AUTHOR]

Today, the exact determination of the parameters of the fracturing of oil and gas fields is of great practical importance. Therefore, an important role is played by computer modeling of the seismic responses from cracks, which correspond to fractured zones actually occurring in nature in terms of the distribution of fracture lengths, positions and rotation angles. Thus, the development of an algorithm aimed at solving this problem plays an important role. In this paper, we have presented the developed algorithm for the placement of cracks in a fractured zone with given geological parameters, such as distribution of lengths, opening, angle of inclination of cracks. The application of this algorithm makes it possible to use in further calculations a geological fractured zone model that is as close as possible to real oil and gas-filled reservoirs. The paper presents the results of test calculations using the grid-characteristic computational method to model wave field scattered on the fractured zone. [ABSTRACT FROM AUTHOR]

Along with the technology development of ocean resources, offshore platforms are gradually becoming larger and more complex. Recent development of the oil and gas field in the deep-water region often involves multiple floating platforms adjacent to each other to perform more complex functions for oil and gas production. This paper describes the investigation carried out on the dynamic responses of a two platforms system containing a Tension Leg Platform (TLP) and a tender assisted drilling (TAD) with a flexible connection between the two platforms. The mooring lines and tendons are taken into consideration in the coupled analysis of the multi-body platform's system. The motion responses and wave load characteristics on the two platforms in multi-body coupled model are investigated in the numerical simulation. Compared to the situation of the two platforms in isolation, it is revealed that the motion responses for the two platforms in coupled model are altered by the combined effects of the platforms' interaction and constrain by the connection. The interaction between platforms can increase both the first- and second-order wave force on platforms in the arrangement direction of two platforms. Quantitative analysis demonstrates their relative importance and thus provides much-needed guidance in practical design of the coupled system. [ABSTRACT FROM AUTHOR]

Foam drainage gas extraction is applied in various natural gas extraction scenarios, such as water-bearing gas wells, gas fields with high water content, and wet natural gas pipeline transport, with the goal of enhancing extraction efficiency and lowering production costs. A common issue in foam-carrying liquid gas wells and wet natural gas pipelines is the large errors observed in the prediction model for liquid accumulation onset, derived using ellipsoidal droplets. Additionally, this model is only applicable to a single surfactant type and concentration. To investigate the effects of different types and concentrations of surfactants on the onset of liquid accumulation. This paper re-establishes the critical foam-carrying flow rate model for spherical cap-shaped foam droplets using Newton's laws of motion, through an analysis of their motion state within the air core. Through the critical foam-carrying flow rate test experiments and foam droplet deformation test experiments to obtain critical foam-carrying flow rate model in the surface tension, foam density, Weber number, drag coefficient and other parameters of the change rule and calculation method. The model's validity was further confirmed using field-measured production data from foam-carrying liquid gas wells, demonstrating accurate validation results. Compared to the previous model, this new model treats foam droplets as spherical cap-shape and introduces a dimensionless scaling factor and foaming capacity to quantify the impact of surfactant types and concentrations on foam droplet surface tension and density. This enhances the model's applicability across different types and concentrations of surfactants with greater accuracy. This offers an efficient, precise, and versatile method for predicting liquid accumulation in foam-carrying liquid gas fields, thereby enhancing the efficiency and safety of gas extraction. [Display omitted] [ABSTRACT FROM AUTHOR]

In this work, the diversity of microbial consortium coming from a shale gas well was initially analyzed by 16 S full length sequencing, and the primary bacteria are Arciella (53.37 %), Shewanella (43.61%), and Desulfovibrio (1.95 %). These bacteria can produce large amounts of H 2 S using sulfate as electron acceptor. Subsequently, microbiologically influenced corrosion (MIC) behavior and MIC inhibition mechanism of norfloxacin and clindamycin hydrochloride are studied. The bacteria in anaerobic microbial consortium (AMC) significantly accelerate steel corrosion, but norfloxacin and clindamycin hydrochloride both can effectively inhibit MIC at a low concentration (40 mg/L) with inhibition efficiencies of 85.2 % and 82.7 %, respectively. [Display omitted] • A good method to solve the potential risks of obsolete antibiotics is proposed based on the strategy of resource conversion. • The primary bacteria are Arciella (53.37 %), Shewanella (43.90 %), and Desulfovibrio (1.95 %) in a shale gas produced water. • Desulfovibrio is not the chief bacterial in this environment. • The bacteria in anaerobic microbial consortium (AMC) significantly accelerate steel corrosion. • Norfloxacin and clindamycin hydrochloride both can effectively inhibit MIC caused by AMC at a low concentration (40 mg/L). [ABSTRACT FROM AUTHOR]

Fluid accumulation in gas wells lead to a sudden drop in production and is a problem. This paper proposes a prediction system for water-producing gas wells using edge intelligence. The method is characterized by use of edge intelligence to realize automatic collection of gas well data, effusion analysis, data backup, upload, production dynamic monitoring, and other functions. The Pearson correlation coefficient was employed to analyze the relevant parameters of liquid accumulation in gas wells. A collaborative discrimination approach utilizing convolutional neural networks and ensemble learning models was implemented to predict liquid accumulation state of gas wells. The model achieved an accuracy rate as high as 98.2%, which aligns well with actual liquid accumulation state of gas wells compared to traditional physical models. In addition, suggestions for extraction and drainage plans are provided based on the degree of liquid accumulation in gas wells, thereby realizing automated and refined management of liquid accumulation wells in the field. This method provides effective theoretical support and reasonable guidance for the efficient development and overall decision-making in gas fields. [ABSTRACT FROM AUTHOR]

• The coupling deposition and plugging of wax and hydrate were systematically investigated. • The coupling solid phase of hydrate and wax is bulk aggregations arch bridge deposition. • The effect of wax on the coupling deposition with different water content is opposite. • The coupling deposition and plugging of wax and hydrate in gas-annular flow has four stages. The coupling deposition and plugging caused by hydrate formation and wax precipitation during the development of deep water natural gas resources bring new industrial challenges and theoretical difficulty. We designed a single-pass pipeline with two types to investigate deposition behavior and systematically performed the coupling deposition and plugging of hydrate and wax experiments in gas–liquid annular flow. The experimental results illustrate that the single solid phase of hydrate is covered layer sheet deposition, while the coupling solid phase of hydrate and wax is bulk aggregations arch bridge deposition. Meanwhile, the natural eddy zone in reducing pipeline accelerates coupling solid particles deposition. Our finds provided the first knowledge on the double effect that wax crystals inhibit particles adhesion and gel network increases aggregations arch bridge blockage. For the low water content in emulsion system, the gel network provides gathering place for hydrate particles, and the arch bridge structure formed by aggregations accelerates the pipeline blockage. The plugging time is shortened by up to 72.6% with the wax concentration increase from 0 wt% to 3 wt%. For the high water content in emulsion system, the majority of wax crystals adsorbed on the hydrate particles and reduce particles cohesion force, which increase the plugging time. Combined with the microscopic morphology evolution perspective of hydrate particles coupled wax, the coupling deposition of hydrate and wax in gas–liquid annular flow has four stages: gas–liquid flow, coupling solid phase formation, coupling solid phase deposition and sloughing, and coupling solid phase plugging. This study can provide theoretical support and design basis for flow assurance program of deep water gas fields and low temperature natural gas transportation pipelines. [ABSTRACT FROM AUTHOR]

Reservoir water sensitivity damage significantly contributes to production declines in low-permeability oil and gas fields. An accurate and rapid assessment of water sensitivity is essential for effective mitigation or prevention strategies. Facing the intricate challenge of predicting high-dimensional water sensitivity damage, this study leverages trends in intelligent drilling and completion technologies. It adopts a Knowledge-guided, Bayesian Optimization-enhanced Light Gradient Boosting Machine (KBO-LightGBM) for modeling, augmented by Multiple Imputation by Chained Equations and Synthetic Minority Over-sampling Technique (MICE-SMOTE) to address missing and unbalanced data issues in oil and gas fields, thereby enhancing the scientific efficacy of data processing. The framework's precision and practicality were confirmed using data from 270 natural core samples across 15 oil fields. Findings include a correlation coefficient of 0.9679 on the test set, a root mean square error of 3.4797, and a mean absolute percentage error of 4.0936%. Interpretability analysis identified formation water mineralization, burial depth, feldspar content, and initial porosity as the predominant factors affecting water sensitivity. This research distinguishes itself with a broader dataset, covering 15 parameters of formation fluids and rock components. Weighting factor α DK and scale β DK were designed to integrate empirical correlations into LightGBM's loss function, theoretically mitigating model overfitting. Hence, the intelligent framework proposed herein accurately predicts reservoir water sensitivity damage, aiding in the development of reservoir damage control strategies. [ABSTRACT FROM AUTHOR]

• Water saturation effects on CO 2 hydrate saturation during CO 2 injection is assessed. • Influence of water memory on the kinetics of CO 2 hydrate is investigated. • Hydrate volume/density during hydrate formation is estimated using medical CT scan. Injection of high-pressure CO 2 into depleted gas reservoirs can lead to low temperatures promoting formation of hydrate in the near wellbore area resulting in reduced injection rates. The design of effective mitigation methods requires an understanding of the impact of crucial parameters on the formation and dissociation of CO 2 hydrate within the porous medium under flowing conditions. This study investigates the influence of water saturation (ranging from 20 % to 40 %) on the saturation and kinetics of CO 2 hydrate during continuous CO 2 injection. The experiments were conducted under a medical X-ray computed tomography (CT) to monitor the dynamics of hydrate growth inside the core and to calculate the hydrate saturation profile. The experimental data reveal increase in CO 2 hydrate saturation with increasing water saturation levels. The extent of permeability reduction is strongly dependent on the initial water saturation: beyond a certain water saturation the core is fully blocked. For water saturations representative of the depleted gas fields, although the amount of generated hydrate is not sufficient to fully block the CO 2 flow path, a significant reduction in permeability (approximately 80 %) is measured. It is also observed that the volume of water + hydrate phases increases during hydrate formation, indicating a lower-than-water density for CO 2 hydrate. Having a history of hydrate at the same water saturation leads to an increase in CO 2 consumption compared to the primary formation of hydrate, confirming the existence of the water memory effect in porous media. [ABSTRACT FROM AUTHOR]

• Workflow enabling geomechanical stability evaluation with uncertain stiffness, thermal expansion, strength for the Zar-3 storage complex. • Monte Carlo simulation enable realistic use of uncertainty. • Method developed that is used to illustrate how geomechanical uncertainty limits the safe operation window in a concrete case during the preparation of a CO2 storage pilot into a depleted oil and gas reservoir in Czech Republic. Carbon Capture and Storage (CCS) is a pre-requisite to decarbonize CO 2 emissions from industrial sectors and as an industry capable of compensating for hard-to-abate emissions in a net zero scenario. A method was developed to evaluate the geomechanical constraints and safe operating envelope as function of pore pressure and temperature. The probability of failure was estimated from uncertain input stiffness and strength data, and as cooling and re-pressurization shifts the in-situ effective stresses, the safe operating envelope was determined, here given by pressure and temperature. Onshore storages nearby industrial clusters enable energy and cost-effective handling of CO 2. In the South-Eastern European region, onshore depleted oil and gas fields located nearby high-emitting industries may developed into CO 2 storages. This paper describes a method for determining maximum fluid pressure as function of temperature from geomechanical restrictions. The method was employed on a practical example used to evaluate the safe operation envelope for a pilot CO 2 injection site into a depleted onshore naturally fractured carbonate oil and gas field. The tool uses Monte Carlo simulations to perform geomechanical stability analyses by sampling from the inherent uncertainty of the input parameters to probability of failure as function of pressure and temperature. The risk of re-opening natural fractures, induced fracturing and fault reactivation are evaluated so the safe operating envelope can be obtained. The uncertainty of the input parameters is thus directly reflected in the safe operating envelope – thus providing an effective communication of value information to external stake holders when maturing a CO 2 storage pilot. [ABSTRACT FROM AUTHOR]

The H 2 S penetration in the nonmetallic biogas pipelines and reinforced thermoplastic composite pipelines can lead to severe environmental pollution and disrupt the regular operations of oil and gas fields. Thus, delving into and comprehending the H 2 S penetration in polyethylene (PE) or polyvinylidene fluoride (PVF2) holds immense significance for both environmental preservation and industrial progress. In this study, Grand Canonical Monte Carlo (GCMC) and Molecular Dynamics (MD) are employed to investigate and contrast the H 2 S penetration property within PE and PVF2 at 300–360 K and 0.1–1.5 MPa. The results indicate the diffusion and penetration coefficients decrease with decreasing temperature and pressure, while the solubility coefficient increases with decreasing temperature. Compared to PE, PVF2 demonstrates stronger resistance to H 2 S penetration, mainly due to H 2 S is difficult to diffuse in PVF2. The relationship between penetration coefficient and temperature is consistent with Arrhenius law. In 0.1 MPa, the activation energy of H 2 S in PE and PVF2 are 31,911 and 42,247 J/mol, respectively. Moreover, the relationship between activation energy and pressure is power function. The study also reveals the H 2 S diffusion in both PE and PVF2 follows the leap mechanism. These research findings can offer valuable guidance for reducing environmental pollution and ensuring industrial development. [Display omitted] • Studying hydrogen sulfide penetration in polyethylene and polyvinylidene fluoride. • Revealing the diffusion mechanism of hydrogen sulfide. • Analyzing the reason of the difference of penetration coefficient. • Polyvinylidene fluoride has strong resistance to hydrogen sulfide penetration. [ABSTRACT FROM AUTHOR]

Membrane distillation (MD) has received ample recognition for treating complex wastewater, including hypersaline oil and gas (O&G) produced water (PW). Rigorous water quality assessment is critical in evaluating PW treatment because PW consists of numerous contaminants beyond the targets listed in general discharge and reuse standards. This study evaluated a novel photocatalytic membrane distillation (PMD) process, with and without a UV light source, against a standard vacuum membrane distillation (VMD) process for treating PW, utilizing targeted analyses and a non-targeted chemical identification workflow coupled with toxicity predictions. PMD with UV light resulted in better removals of dissolved organic carbon, ammoniacal nitrogen, and conductivity. Targeted organic analyses identified only trace amounts of acetone and 2-butanone in distillates. According to non-targeted analysis, the number of suspects reduced from 65 in feed to 25–30 across all distillate samples. Certain physicochemical properties of compounds influenced contaminant rejection in different MD configurations. According to preliminary toxicity predictions, VMD, PMD with and without UV distillate samples, respectively contained 21, 22, and 23 suspects associated with critical toxicity concerns. Overall, non-targeted analysis together with toxicity prediction provides a competent supportive tool to assess treatment efficiency and potential impacts on public health and the environment during PW reuse. [Display omitted] • Non-targeted chemical screening tools were used to evaluate treated produced water. • Fates of different suspect compounds were studied. • Photocatalytic membrane distillation resulted in better removal of dissolved organics. • Human health and environment-based concerns of suspect compounds were discussed. • Non-targeted chemical screening is helpful in identifying critical target analytes. [ABSTRACT FROM AUTHOR]

Subsea flowlines are flexible or rigid pipelines that are used in oil and gas fields commonly for transporting production fluids from wells. The majority of the flowlines operating in basins across the world (including e.g. Australia's 1700 km infield flowlines) are approaching the end of their productive life, and will need to be decommissioned over the next 5 decades. This paper, for the first time, investigates the potential of repurposing decommissioned flowlines to dynamically installed anchors for mooring floating facilities. Five shapes of anchor have been developed using segments of flowline. Two series of tests were subsequently carried out on models of those shapes. The first series of tests involved releasing the models in still water to assess free-fall trajectory (i.e. verticality), terminal velocity, and anchor drag coefficient. The second series of tests were carried out at 50 g in clay to investigate the performance of the anchors in terms of tip embedment depth during dynamic installation and capacity under vertical loading. The results confirmed performance similar to conventional dynamically installed anchors, suggesting that there is potential to fabricate offshore anchors using segments of flowline. • Decommissioned flowlines. • Repurposing decommissioned flowlines to dynamically installed anchors. • Verticality, terminal velocity, and drag coefficient in water. • Tip embedment depth during dynamic installation in clay. • Capacity under monotonic vertical loading in clay. [ABSTRACT FROM AUTHOR]

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12–8.39 × 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development. • The relationship between the timing of gas accumulation and the evolution of reservoir quality is elucidated. • The mechanisms of gas accumulation and the factors influencing variations in gas saturation are detailed. • Formation and tight sandstone rock typing with exploration and development potential are clarified. [ABSTRACT FROM AUTHOR]