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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]

Optimizing well placement is one of the primary challenges in oil field development. The number and positions of wells must be carefully considered, as it is directly related to the infrastructure cost and the profits over the field's life cycle. In this paper, we propose three estimation of distribution algorithms to optimize well placement with the objective of maximizing the net present value. The methods are guided by an elite set of solutions and are able to obtain multiple local optima in a single run. We also present an auxiliary regression model to preemptively discard candidate solutions with poor performance prediction, thus avoiding running computationally expensive simulations for unpromising candidates. The model is trained with the data obtained during the search process and does not require previous training. Our algorithms yielded a significant improvement compared to a state-of-the-art reference method from the literature, as evidenced by computational experiments with two benchmarks. [ABSTRACT FROM AUTHOR]

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

Oil and gas pipeline safety analyses aim to enhance the integrity management and operational safety of pipelines to prevent major incidents. This study seeks to provide a comprehensive overview of the evolution of research hotspots and knowledge frontiers in global oil and gas pipeline safety. A bibliometric data mining method was adopted to systematically sort out 2,582 studies in the field of oil and gas pipeline safety retrieved from the core database of Web of Science from 2000 to 2023. A bibliometric network analysis was conducted to investigate the distribution of papers in terms of time, geographic region, organization, main author, journal cocitation, and literature cocitation, and to identify the research hotspots and frontiers. The findings revealed that the number of papers on oil and gas pipeline safety has surged from 10 in 2000 to 327 in 2023, reflecting an overall exponential growth trend. Key research contributions in this field predominantly originate from institutions such as the China University of Petroleum (Beijing), Southwest Petroleum University, and China University of Petroleum (East China). These institutions, located primarily in China, have had a significant impact on the field. Notable researchers, including Li Yuxing, Faisal Khan, and Zhang Hong, have made substantial contributions. Leading journals, such as Journal of Loss Prevention in the Process Industries, Process Safety and Environmental Protection, and Energies, have published the highest number of influential papers in this area. The research indicates that although a foundational theory and research framework for oil and gas pipeline safety have been established, numerous research directions and cutting-edge branches continue to emerge. Prominent among these are studies focusing on pipeline reliability analysis, risk assessment, failure prediction, leakage, and multiphase flow assurance, using numerical simulations and machine learning techniques. This study provides a theoretical basis and practical guidance for advancing oil and gas pipeline safety analysis and accident prevention. [ABSTRACT FROM AUTHOR]

Failure analysis is a vital technique that is intended to strengthen the integrity management of oil and gas pipelines. The significance is to reduce economic losses and avoid or minimize major failure incidents. The aim of this study is to use bibliometric methods to research 2,533 papers retrieved from the Web of Science database spanning from 2004 to 2023. The analysis conducted using VOSviewer, focused on temporal trends, geographic distribution, major organizations, leading authors, journal co-citations, and literature co-citations. The objective is to uncover research hotspots and frontiers, providing insights to advance failure analysis and prevention techniques. The findings revealed a substantial surge in the number of papers related to failure analysis, escalating from 16 in 2004 to 190 in 2023, indicating an overall exponential growth trend. This growth has been most pronounced over the past 8 years. Noteworthy contributors to this field include China, the USA, Canada, England, and Iran, with Iran, Australia, and Italy exerting significant impact. In addition, the top three research producers are all from institutions or universities located in China. The journals Engineering Failure Analysis, International Journal of Pressure Vessels and Piping, and Journal of Loss Prevention in the Process Industries exhibit the highest publication numbers. Significantly, Journal of Loss Prevention in the Process Industries and Gas Science and Engineering emerge as influential and highly regarded publications within this field. The study revealed that while the foundational theory and research framework in oil and gas pipeline failure have crystallized, a plethora of research directions and cutting-edge branches continue to emerge. Notably, the study of failure possibilities and behavior through Bayesian networks, failure characterization analysis, and finite element methods have emerged as the primary development directions and research hotspots. In terms of innovation, the application of bibliometric methods has enhanced the capacity to handle extensive literature databases and conduct network analyses. This study furnishes a theoretical foundation and guidance for the advancement of failure analysis and prevention techniques in the field of oil and gas pipelines. [ABSTRACT FROM AUTHOR]

The Asmari succession is among the greatest productive hydrocarbon-bearing rock units in the Middle East. This paper examines the biostratigraphy, sedimentary environment, and depositional sequence of the Asmari reservoir in the Haft-Kel Field. This succession in the Haft-Kel Field contains limestones, dolostones, anhydrites, and argillaceous limestones and is bounded between the Pabdeh and Gachsaran formations. Paleontological research has led to the creation of three assemblage zones in this region. These zones present an age range from the late Oligocene (Chattian) to the early Miocene (Aquitanian). Also, detailed petrographic examinations and facies analysis led to the recognition of 14 types of microfacies, ranging from open marine environments to intertidal and supratidal systems. The distribution and association of recognized microfacies proposed carbonate ramp-type platform deposition for the Asmari Formation. In addition, three third-order depositional sequences (sequences 1, 2, and 3) have been recognized through the Asmari Formation in the Haft-Kel Oil field that is well correlated with sequences IV, V, and VI proposed by van Buchem et al. (2010), respectively. Using the Hydraulic Flow Unit (HFU) concept, six rock types have been identified for the Asmari reservoir. Finally, three reservoir zones, comprising none, moderate, and good reservoir zones, were introduced for the Asmari reservoir in Haft-Kel Field. No reservoir zones are visited in the lower part of the formation in depositional sequence 1 and to some extent in the Low Stand Systems Tract (LST) part of depositional sequence 2 and 3, while moderate to good reservoir zones are developed in the upper intervals of the formation, especially in the High Stand Systems Tract (HST) parts of depositional sequence 2 and 3. [ABSTRACT FROM AUTHOR]

Purpose: This study aims to explore how operational resilience can be achieved within supply ecosystems in the delicate yet harsh natural environments of the Arctic. Design/methodology/approach: An in-depth, multiple qualitative case study of offshore supply operations in Arctic oil and gas field projects is conducted. Data from semi-structured interviews, personal observations and archival materials are analysed through institutional work and logics approaches. Findings: The findings suggest that achieving social-ecological resilience depends on the interaction between social and natural (irreversible) systems, which are shaped and influenced by various institutional dynamics. Different resilience solutions were detected. Research limitations/implications: This study develops a comprehensive understanding of how social-ecological resilience emerges in supply ecosystems through institutional dynamics. The study's empirical basis is limited to offshore oil and gas projects in the Arctic. However, due to anticipated future growth of Arctic economic activities, other types of supply ecosystems may benefit from the study's results. Originality/value: This research contributes with empirical knowledge about how social-ecological resilience is created through institutional interaction within supply ecosystems to prevent disruptions of both social and ecological ecosystems under the harsh natural conditions of the Arctic. [ABSTRACT FROM AUTHOR]

This study highlights the challenges in using environmentally friendly corrosion inhibitors in a variety of industries by examining the effects of avocado extract as a corrosion inhibitor on the corrosion behavior of carbon steel in salty formation water (SFW) generated from West Egyptian petroleum fields. A combination of weight loss and electrochemical experiments were used to examine the corrosion properties of carbon steel at different avocado extract concentrations (20–100 mg L–1). A number of methods, including scanning electron microscopy (SEM), energy dispersive X-ray (EDAX), and UV–Visible analyses were employed to identify the configuration and chemical components of corroded substrates. The avocado extract demonstrated the highest inhibition corrosion efficiency value at a concentration of 100 mg L−1, exhibiting an inhibitory effectiveness of approximately 92.4%. The adsorption isotherm of avocado extract has been identified as the Langmuir type, exhibiting cathodic-anodic efficiency. The addition of avocado extract increases the activation energy of the oxidation reaction from 13.8 1 to 51.6 kJ mol−1. This work offers a newly viewpoint for future research on the prevention of carbon steel corrosion by extracting an effective avocado extract for the first time in an SFW solution. [ABSTRACT FROM AUTHOR]

The carbonate fracture-cave reservoir in the Tahe oilfield, China, encounters development challenges because of its substantial burial depth (exceeding 5000 m). Its characteristics are low permeability, pronounced heterogeneity, extensive karst cavern systems, diverse connection configurations, and intricate spatial distribution. Prolonged conventional water flooding leads to predominant water channels, resulting in water channeling and limited sweep efficiency. Surfactant flooding is usually adopted in these conditions because it can mitigate water channeling and enhance sweep efficiency by lowering the interfacial tension (it refers to the force that is generated due to the unbalanced molecular attraction on the liquid surface layer and causes the liquid surface to contract) between oil and water. Nonetheless, the Tahe oilfield is a carbonate reservoir where surfactant is prone to loss near the well, thereby limiting its application. High-pressure injection flooding technology is an innovative method that utilizes injection pressure higher than the formation rupture pressure to alter reservoir permeability, specifically in low-permeability oil fields. Because of the high fluid flow rate, the contact time with the interface is decreased, enabling the ability for surfactants to reach the deep reservoir. In this article, based on the mixed adsorption mechanism of two surfactants and the hydrophilic and lipophilic equilibrium mechanisms, a set of high-temperature and high-salinity resistance surfactant systems appropriate for the Tahe oilfield is developed and its associated performance is evaluated. An oil displacement experiment is carried out to examine the effect of surfactant flooding by high-pressure injection. The results demonstrate that the ideal surfactant system can lower the interfacial tension to 10−2 mN/m and its capacity to reduce the interfacial tension to 10−2 mN/m after different aging periods. Besides, the surfactant system possesses excellent wettability (wetting angle changed from 135° to 42°) and certain emulsifying abilities. The oil displacement experiment shows that the oil recovery rate of surfactant flooding by high pressure reaches 26%. The effect of surfactant flooding by high-pressure injection is better than that of high-pressure injection flooding. [ABSTRACT FROM AUTHOR]

Diatomaceous earth (diatomite) is a material that exhibits unique properties that can be used in many areas of the economy. The use of diatomite as a sorbent for absorbing oil substances has been known for many years. Diatomite, thanks to its structure, acts like a sponge, absorbing oil substances. Its micropores increase the surface area in contact with the pollutant, which speeds up the absorption process. Diatomite is used to clean up oil spills on land and water, secure industrial sites, treat wastewater, and manage pollution at ports and oil ports. Many scientific papers to date have focused on evaluating the potential of diatomite as a medium for petroleum substances. Still, there is little mention of the potential for using diatomite as a carrier for paraffinic PCMs. Paraffins are synthetic compounds obtained by distillation from a specific fraction of crude oil. This paper presents a study of the physicochemical properties of diatomite with a view to its subsequent use as a medium for absorbing paraffinic phase change materials. Thanks to its high porosity, high specific surface area, low density, and chemical inertness, this material is an ideal medium for paraffinic substances. In addition, its most important feature is the absence of desorption. A new type of environmentally friendly and cheap phase change materials may contribute to the increase in the use of this type of materials in construction. The benefits of using PCM materials are known. [ABSTRACT FROM AUTHOR]

In Colombia, natural hydrogen (H2) was recently declared a source of unconventional renewable energy. An opportunity has been recognized to take advantage of information on the infrastructure of oil fields as a springboard for H2 exploration in the country's sedimentary basins. Establishing similarities and identifying components of the possible H2 systems in the different geological contexts where the presence of H2 has been proven in Colombia's sedimentary basins allows the establishment of the probability of H2 in the Ecopetrol oil and gas fields in Colombia. The components of H2 systems include potential H2 source rocks and reservoirs. Potential accumulations need to be confirmed through measurements, sampling, and well testing. The main types of H2 well exploration carried out in this study resemble those in oil fields and include surface surveys, logging while drilling (mud gas and petrophysics), and downhole sampling. In the case of a hydrocarbon field in the Llanos Basin, a detailed seismic and geological review, supported by surface survey indications of H2 traces, prompted further investigation while drilling wells in the basin to establish the provenance and distribution of H2. Based on the proposed workflows, we evaluated possible strategies in the area. Given the positive evaluation of the possible elements of a theoretical H2 strategy, a sampling plan was defined both in the well and on the surface that will reduce the uncertainty of the prospect of natural H2 in the studied basin but may also be applied to similar geological settings worldwide. This study shows the application of such an H2 exploration strategy, leading to the presented results from the first well and confirming the presence of an active natural H2 system in the Llanos Basin. [ABSTRACT FROM AUTHOR]

In the area of reservoir engineering, the optimization of oil and gas production is a complex task involving a myriad of interconnected decision variables shaping the production system's infrastructure. Traditionally, this optimization process was centered on a single objective, such as net present value, return on investment, cumulative oil production, or cumulative water production. However, the inherent complexity of reservoir exploration necessitates a departure from this single-objective approach. Multiple conflicting production and economic indicators must now be considered to enable more precise and robust decision-making. In response to this challenge, researchers have embarked on a journey to explore field development optimization of multiple conflicting criteria, employing the formidable tools of multi-objective optimization algorithms. These algorithms delve into the intricate terrain of production strategy design, seeking to strike a delicate balance between the often-contrasting objectives. Over the years, a plethora of these algorithms have emerged, ranging from a priori methods to a posteriori approach, each offering unique insights and capabilities. This survey endeavors to encapsulate, categorize, and scrutinize these invaluable contributions to field development optimization, which grapple with the complexities of multiple conflicting objective functions. Beyond the overview of existing methodologies, we delve into the persisting challenges faced by researchers and practitioners alike. Notably, the application of multi-objective optimization techniques to production optimization is hindered by the resource-intensive nature of reservoir simulation, especially when confronted with inherent uncertainties. As a result of this survey, emerging opportunities have been identified that will serve as catalysts for pivotal research endeavors in the future. As intelligent and more efficient algorithms continue to evolve, the potential for addressing hitherto insurmountable field development optimization obstacles becomes increasingly viable. This discussion on future prospects aims to inspire critical research, guiding the way toward innovative solutions in the ever-evolving landscape of oil and gas production optimization. [ABSTRACT FROM AUTHOR]

The use of mini-hydrocyclones for downhole oil–water separation has been proposed due to their small size, convenient arrangement, simple structure, and high separation efficiency, all of which contribute to an improved economic recovery rate in oil fields. Currently, mini-hydrocyclones are primarily used for solid–liquid separation, and the flow field characteristics and mechanisms for improving the separation efficiency of mini-hydrocyclones in liquid–liquid separation are not fully understood. This paper elucidates the mechanism of high efficiency in oil–water separation mini-cyclones from a flow field perspective by combining numerical simulations with high-speed photography. The focus is on investigating the flow field characteristics of mini-cyclones with different diameters, including velocity fields, pressure fields, and oil nuclei morphology. The results show that under an oil volume fraction of 2%, the Euler numbers of mini-hydrocyclones with diameters of 30, 24, and 18 mm are 0.23, 0.25, and 0.34 times those of the 12 mm mini-hydrocyclone, respectively, while the Reynolds numbers are 4.20, 3.60, and 2.29 times those of the 12 mm mini-hydrocyclone. This suggests that a smaller mini-hydrocyclone diameter leads to higher energy consumption, weaker turbulence, and better separation efficiency. Under identical operating conditions, a smaller mini-hydrocyclone diameter results in lower tangential and axial velocities, which increases the residence time of fine oil droplets within the device, thereby improving the separation effect. Additionally, an adaptability study of mini-hydrocyclones with different diameters under the same separation ratios and inlet flow conditions was conducted using both numerical simulations and laboratory experiments. The findings reveal that, under the same operating conditions, the smaller the diameter of the mini-hydrocyclones, the higher their efficiency. Under the optimal operating conditions within the scope of the study, the separation efficiencies of the 12 and 24 mm mini-hydrocyclones were 99.8% and 98.5%, respectively. Additionally, the experimental and simulated data for separation efficiency and underflow oil concentration demonstrate a second-order fitting result greater than 0.92, indicating a high degree of consistency. [ABSTRACT FROM AUTHOR]

Effective suppression of flammable liquid fires depends on the rapid formation of a closed water film by aqueous film-forming foam (AFFF) over the oil surface. To investigate the mechanism of film formation on the oil surface with a compounded solution using the fluorocarbon betaine amphoteric surfactant (OC5-Betaine) as the active ingredient, a multi-angle visualization experiment was applied to capture the impact and spreading of the surfactant-laden droplets on a 25 mm deep corn oil pool synchronously, within a Weber number (W e) range of 7–168. The results revealed that various characteristic impact phenomena strongly correlate with the W e. The critical W e for complete floating of a droplet or partial droplet sink to the bottom of oil pool after impact is approximately 155. There are two patterns, "Nipple" and "Mushroom," when the droplet impacts the oil surface and sinks to the lowest point. When the W e exceeds 90, the droplets consistently adopt the Mushroom shape. For a given W e , the maximum depth and maximum penetration time of the Nipple type are greater than those of the Mushroom type. There is a high probability of "Rebound static" phenomenon for the Nipple type, which slows spreading. A range of W e between 90 and 140 promotes rapid droplet spreading and prevents jet breakup, making it optimal for firefighting. These findings offer insights for developing more effective AFFFs. [ABSTRACT FROM AUTHOR]

Microbiologically influenced corrosion (MIC) is a universal issue of significant concern in the petroleum industry, with the potential for enormous economic losses and casualties. This study focused on the effect of temperature on MIC and the corrosion mechanism. The corrosion rate, morphology, corrosion products, and microbial community composition of produced fluid samples from the Zhanjiang oilfield were measured after anaerobic culture at 30 and 60 °C for 14 days. The corrosion rate of the Z1 and Z2 samples decreased with increasing temperature, while the corrosion rate of the Z3 sample changed from light corrosion to heavy corrosion. The Z1 sample was dominated by pitting corrosion, the Z2 sample had a relatively smooth surface, and the Z3 sample was observed to have one dimensional wormhole corrosion at 60 °C. The microbial community composition by 16S ribosomal deoxyribonucleic acid (rDNA) sequence showed that the bacterial communities were dominated by Pseudomonas and Bacillus, and the archaeal communities were mainly composed of Methanothermobacter, Methanosaeta, and Candidatus Nitrosotenuis, which was prevalent in Z3 samples at 60 °C. It suggested that MIC could be caused by extracellular electron transfer and reduction of nitrate or nitrite to N2 and NH 4 + by bacteria, and utilization of CO2 to produce CH4 by archaea. Overall, the results of this study can provide comprehensive data and new insights into corrosion management strategies for oil fields. [ABSTRACT FROM AUTHOR]

To study the fire behavior of UHVDC (ultra-high-voltage direct current) converter transformers and the effectiveness of CAFs (compressed air foams) in suppressing fires, a full-scale model of a 220 kV converter transformer fire was constructed. The model mainly considered the oil pool fires and oil spill fires that form after explosions, causing the casing to completely fall out. The hot oil fire tests were conducted on the physical converter transformer. The fire suppression characteristics of the CAF system for converter transformer fires were studied. The temperature and changes in various locations of the fire model were analyzed under different foam supply strengths. The fire in a converter transformer is characterized by intense heat, high temperatures, and strong radiation. The highest temperature can exceed 1000 °C in cases of complete combustion. The fire in the converter transformer involves a dynamic oil spill and a large pool of oil, making it challenging to extinguish. The fire extinguishing performance and cooling effect of CAFs are outstanding. The recommended foam supply strength for the actual project is more than 8 L/(min·m2). [ABSTRACT FROM AUTHOR]

Concerning the entrance of oil into the Persian Gulf due to the presence of oil fields in this ecosystem, a wide investigation was carried out in 2017 to evaluate the hydrocarbons source identification and chemical fingerprinting. To this end, surface sediments were collected from the Persian Gulf. In the laboratory, compounds (n-alkanes, PAHs, hopane and sterane) were then extracted with a Soxhlet system and two steps of chromatographic columns and analyzed using a GC–MS instrument. The results showed that the concentrations of the n-alkanes and Σ30 PAHs increased with a reduction in distance from hot spots. This suggests that high concentrations of hydrocarbons in the locations near the hot spots might be due to oil leakage, transportation of and exploration for oil, pipeline fractures and industrial activities. A positive relation between total organic matter (TOM) and hydrocarbons was observed. A common petrogenic hydrocarbon source was strongly implied in most places by the presence of unresolved compounds resolved (UCM), lower molecular weight/higher molecular weight (LMW/HMW) and carbon preference index (CPI) ratios < 1. Typical profiles of petrogenic PAHs with predominant alkyl substituted naphthalene and phenanthrene, various PAH ratios and multivariate analysis showed that PAHs were mainly derived from petrogenic sources. Simultaneous use of n-alkanes and PAHs in source identification can be effective to precisely specify the hydrocarbon sources in complicated mixture ecosystems. Furthermore, using multivariate analysis and chemical fingerprinting of n-alkanes, PAHs, hopanes and sterane confirmed that Hendijan crude oil may be the source of the sediment pollution in the study area. [ABSTRACT FROM AUTHOR]

To circumvent the numerous deficiencies inherent to water-based fracturing fluids and the associated greenhouse effect, CO2 fracturing fluids are employed as a novel reservoir working fluid for reservoir reconstruction in unconventional oil fields. Herein, a mathematical model of CO2 fracturing crack propagation based on seepage–stress–damage coupling was constructed for analysing the effects of different drilling fluid components and reservoir parameters on the crack propagation behaviour of low permeability reservoirs. Additionally, the fracture expansion mechanism of CO2 fracturing fluid on low permeability reservoirs was elucidated through mechanical and chemical analysis. The findings demonstrated that CO2 fracturing fluid can effectively facilitate the expansion of cracks in low-permeability reservoirs, and thickener content, reservoir pressure, and reservoir parameters were identified as influencing factors in the expansion of reservoir cracks and the evolution of rock damage. The 5% CO2 thickener can increase the apparent viscosity and fracture length of CO2 fracturing fluid to 5.12 mPa·s and 58 m, respectively, which are significantly higher than the fluid viscosity (0.04 mPa·s) and expansion capacity (13 m) of pure CO2 fracturing fluid. Furthermore, various other factors significantly influence the fracture expansion capacity of CO2 fracturing fluid, thereby offering technical support for fracture propagation in low-permeability reservoirs and enhancing oil recovery. [ABSTRACT FROM AUTHOR]

The energy transition demands innovative solutions for efficient and sustainable oil and gas production, particularly for heavy and extra-heavy crude. A significant challenge in these operations is the excessive production of water, which increases operational costs and environmental impact. This paper reviews the application of mechanical water control devices to optimize water management in heavy oil fields. By analyzing over 3140 documents, only a final total of 42 previous peer-reviewed articles were considered, where 58% sought to understand and optimize water flow from the reservoir to the well mainly by well simulation; 19% studied the implementation cases in the fields, highlighting the success cases; 16% mentioned CFD and other simulations tools; and 7% are related to these devices. While simulation studies have been widely employed, there is a need for more comprehensive field implementations and data-driven insights. This paper aims to contribute to the advancement of water management techniques, ultimately enhancing the sustainability and profitability of heavy oil production, emphasizing the most significant findings. [ABSTRACT FROM AUTHOR]

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Paving oil and gas field well sites of drilling waste allow us to reuse solid waste. However, to keep the risk within acceptable limits, some questions need to be answered: what is the dilution effect that soil and groundwater have on the transport of pollutants? What is the minimum concentration of pollutants leached from drill wastes? In this study, we focus on the paving of well sites using drilling wastes, and we analyze the pollutant migration pattern in the soil vadose zone and groundwater mixing zone after rainwater leaching. The drilling waste pollutant protective concentration level (PCL) and the corresponding dilution attenuation factor (DAF) were then proposed. In addition, the PCL's accessibility, uncertainty, and environmental significance were further analyzed. It was found that the pollutant dilution factor (DF) of the groundwater mixed zone was strongly influenced by the thickness of the mixed zone, the groundwater Darcy rate, the length of the contaminant source, and the permeability, and each contributed approximately 25%. The soil vadose zone attenuation factor (AF) was primarily influenced by the soil vadose zone (i.e., groundwater depth) thickness that contributed approximately 53%. The contaminant DAF values of the well site drilling waste paving (e.g., the soil vadose zone thickness ranged from 5 to 30 m) ranged from 12 to 84. Additionally, the PCL values of the contaminants ranged from 12 to 84 times of the acceptable concentration (e.g., the Class III permissible limits of the Groundwater Quality Standards GB/T 14848-2017) at the groundwater compliance point. The expression for the exponential relationship between the DAF or PLC and the depth of the soil vadose zone was also provided in this study. The study results provide a reference for the actual process of the use of drilling wastes to pave well sites and for solid waste treatment or soil remediation decision-making and the associated risk assessment procedures. [ABSTRACT FROM AUTHOR]

Lost circulation has the potential to cause formation damage, wellbore instability and a blowout. Many methods have been introduced, but there is no industry-wide solution available to predict lost circulation due to some constraints in the field. It is essential to predict the onset of loss of circulation to mitigate its effects, reduce operational costs and prevent the risk to people and the environment. A wide range of methods, techniques and treatments, including environmentally friendly materials, are reviewed to mitigate the loss of circulation. Conventional and intelligent methods are presented for detecting and predicting lost circulation events. Using oil field data such as fluid parameters, drilling parameters and geological parameters, artificial intelligence can predict fluid losses using supervised machine learning (ML). Several ML models for predicting fluid loss are reviewed in this paper, and other possible applications are discussed. The sample size, field location, input and output features, performance and ML algorithms are extracted. The paper provides an inclusive presentation of the ML workflow for fluid loss prediction and is anticipated to help and support both drilling engineering practitioners and researchers in the resolution of drilling challenges, with recommendations for future development. [ABSTRACT FROM AUTHOR]

Environmental protection requirements and the need to increase the proportion of oil recovered by secondary methods have led to the rise in popularity of microbial enhanced oil recovery (MEOR) techniques. Usually, MEOR requires the use of indigenous strains of microorganisms residing in wells, as they are adapted to local conditions. However, for some wells and fields, such as the Boca de Jaruco field in Cuba, information about the oilfield microorganisms and their properties is extremely limited. One of the properties crucial for the successful implementation of MEOR in fields is the ability of indigenous strains to produce biosurfactants. The aim of the present study is to evaluate the ability of six bacterial isolates obtained from the Boca de Jaruco field in Cuba to produce biosurfactants. The isolates capable of utilizing oil as their sole carbon source were identified as Bacillus subtilis (strains CC21, CC23, CC31, and CC32), Bacillus licheniformis (strain CC33), and Aeromonas veronii (strain CC22). It was determined that all isolates can tolerate temperatures between 30 and 60 °C, salinity ranging from 0.5 to 10.0% NaCl, and pH levels between 6 and 9. Regarding their ability to produce biosurfactants, assessed using the drop collapse method, oil-spreading method, emulsification activity test, and surface tension measurement, the isolates ranked as follows: A. veronii CC22 > B. subtilis CC21 = B. subtilis CC31 > B. subtilis CC23 = B. subtilis CC32 > B. licheniformis CC33. The biosurfactants produced were stable in the presence of 1.7 to 20.0% NaCl, irrespective of temperature (30 or 70 °C). However, substituting 20% of the NaCl with CaCl2 resulted in destabilization of the biosurfactants produced by all investigated isolates, with destabilization levels averaging up to 32% at 70 °C. [ABSTRACT FROM AUTHOR]

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

Producing hydrogen from coal with carbon capture, utilization and storage (CCUS) could be pivotal to establishing a hydrogen economy. It is crucial to study the behavioral strategies of the parties involved in the diffusion of CCUS technology. This paper fills the gap in existing research by developing an evolutionary game model between energy companies and oil fields with commercial cooperation to analyze their interactions. Based on the numerical simulation, the effects of critical parameters on evolution trajectories were analyzed and discussed. The results indicate that neither coal-to-hydrogen enterprises nor oil fields are presently willing to participate in CCUS projects, so appropriate incentives must be taken to promote its advancement. Empirical studies have found that, with other conditions unchanged: (i) A blue hydrogen price of CNY 35.6/kg H 2 and a carbon market price of CNY 150/t CO 2 can promote hydrogen production enterprises to engage in low-carbon production; (ii) The establishment of a carbon tax policy about CNY 130/t CO 2 can also motivate hydrogen plants to install carbon capture devices and reduce greenhouse gas emissions to avoid heavy penalties; (iii) A mature oil market and its high price level is sufficient to offset the inhibiting effect of higher carbon market prices on the willingness of oil fields to cooperate; (iv) Government subsidy policies need to be organically combined with market mechanisms such as carbon tax to effectively reduce the investment risks of enterprises and promote project cooperation. • Evolutionary game analysis of the CCUS technology adoption is conducted. • Coal-to-hydrogen plants and oil fields are considered in the game. • Both of the two stakeholders are not willing to adopt the CCUS currently. • Increasing carbon and hydrogen prices can increase the adoption intentions. • Government subsidy policy alone is not enough to drive the CCUS adoption. [ABSTRACT FROM AUTHOR]

Due to the Al 2 O 3 protective film on the surface of aluminum alloys, the aluminum-water reaction is limited. However, the introduction of active elements such as Ga, In, and Sn can disrupt this film, enabling the aluminum alloy to react with water, dissolve, and produce H 2. In this paper, active aluminum alloys are categorized based on their applications: hydrogen-production-type and structural-type. For hydrogen-production-type active aluminum alloys, the methods to improve the hydrolysis efficiency, including different preparation methods, alloying elements, microstructure, etc for the application in hydrogen clean energy fields are reviewed. For structural-type active aluminum alloys, the effect of strengthening elements and low melting point elements on mechanical properties for the application in petroleum exploration fields are summarized in detail. And the composition and properties between hydrogen-production-type and structural-type active aluminum alloys are compared and analyzed. Finally, the development direction of active aluminum alloys on energy field is put forward. • Hydrogen-production-type ((Ga, In, Sn) > 10%) active aluminum alloy is summarized. • Structural-type ((Ga, In, Sn) < 5%, (Mg, Cu, Zn) < 5%) active alloy is reviewed. • Hydrogen-production rate is also influenced by temperature, pressure, pH and grain size. • Structural-type alloys possessed high ductility or strength are suitable for downhole tools. [ABSTRACT FROM AUTHOR]

As the demands for hydrocarbon exploration continue to rise, the identification of thin sand bodies becomes significantly important for subsequent petroleum exploration and development efforts. However, traditional inversion techniques struggle with complex subsurface structures because of the low frequency seismic data. To characterize the architecture of hydrocarbon reservoir precisely, a novel seismic inversion method is applied to improve the resolution of seismic data for a high interpretation accuracy. In this study, we take the X Oilfield in Eastern China as an example, adopted a novel approach combining spectral decomposition with convolutional neural networks (CNNs) within a genetic algorithm (GA) framework for inversion. The CNNs are adept at recognizing and interpreting the spatial configurations in the data, thereby establishing a high correlation between seismic attributes and sand body distributions. GA helps CNNs to get an optimal solution in a fast speed. The results reveal that the model's sand thickness predictions closely match the actual measurements at wells, with a new horizontal well's alignment with the predicted output reaching an accuracy of 85.1%. Compared to traditional seismic inversion methods, our method requires less data. This approach may find a wider application, especially at offshore oilfields with few wells data and low quality seismic data. [ABSTRACT FROM AUTHOR]

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

The production of hydrogen sulfide (H2S) had caused huge economic losses and security risks to oil fields, which had attracted the attention of many researchers. Studies focused on hypersaline oil reservoirs were scarce. Here, we simulated H2S inhibition by adding NO3- and NO2- in anaerobic bottles and up-flow sand-packed bioreactor in the laboratory using water samples from injection wells in the Jianghan reservoir. The microbial characteristics, pH, salinity, sulfate, sulfide, NO3- and NO2- were measured at every stage. The content of H2S and elemental sulfur (S0) gradually reduced to 0 mg/L with injected 400 mg/L of NO3- and 300 mg/L of NO2-. Halophilic nitrate-reducing bacteria (NRBs) related to Halomonas and Arcobacter could suppress the activity of sulfate-reducing bacteria (SRBs) through the accumulation of nitrite toxicity and the competition of organic substrates with SRBs. When SRBs activity could not be suppressed, the sulfur-oxidizing bacteria related to Sulfurimonas, Thiomicrospira and Acrobacter were accumulated for souring control through microbial sulfur cycle of H2S production and oxidation. Salinity could be a key parameter affecting microbial development and interactions. This study provides a fundamental data to souring control in the hypersaline oil reservoir by reinjection produced water amended with NO3- and NO2-. [ABSTRACT FROM AUTHOR]

Most of the oil fields in China have entered the stage of high-water-content development, which has become the primary means to improve the recovery rate of high-water-content oil fields by changing the injection agent. MDFFA membrane oil drive technology is a new type of tertiary oil recovery technology that uses an aqueous solution as the transfer medium; however, it is rarely applied in the field of tight oil reservoirs in China. In this study, molecular film-wall microgravity and water-wall microgravity were compared for tight reservoirs in the Shengli oilfield. It was concluded that the MDFFA dominates in competitive adsorption, breaks through and removes the hydrated layer, and finally adsorbs firmly on the pore wall to form a nanoscale ultrathin film. The application conditions of the MDFFA were also explored, and its wetting angle was tested. Further, the variation law of MDFFA adsorption was studied, and the mechanism of MDFFA drag reduction was explained in terms of reducing the boundary layer effect and water injection friction resistance. The natural cores procured from the Shengli tight oil field were analyzed for MDFFA membrane drive cores, and a reasonable injection concentration was selected. Through a series of mechanistic and experimental studies, we provided theoretical and technical references for the development of increased tight oil production. [ABSTRACT FROM AUTHOR]

This work aims to study the use of polyamide 12 in oil pipelines to replace steel, which is more susceptible to corrosion. Pipes of polyamide were installed in oil fields and, after 1 year of operation, were removed and analyzes. The outer layers of all field samples and the unaged sample did not show, in the DSC, any primary peak close to the melting peak. This is due to the extrusion and the formation of different crystalline structures on the inner surface, giving rise to two melting peaks. All layers of the field samples showed endothermic peaks, but the unaged sample did not. This can be attributed to the annealing process, but this phenomenon does not affect the properties PA12. The results showed no degradation and PA12 can be a viable alternative for oil pipelines, providing savings of more than 50% compared to steel, in addition to operational, human and environmental safety. [ABSTRACT FROM AUTHOR]

Due to the significance of carbon utilization and storage, CO2 huff and puff is increasingly receiving attention. However, the mechanisms and effects of CO2 huff and puff extraction in medium to deep saturated heavy oil reservoirs remain unclear. Therefore, in this study, by targeting the medium to deep saturated heavy oil reservoirs in the block Xia of the Xinjiang oil field, measurements of physical properties were conducted through PVT analysis and viscosity measurement to explore the dissolution and diffusion characteristics of CO2-degassed and CO2-saturated oil systems. Multiple sets of physical simulation of CO2 huff and puff in medium to deep saturated heavy oil reservoirs were conducted using a one-dimensional core holder to evaluate the EOR mechanism of CO2 huff and puff. The results demonstrate that the solubility of CO2 in degassed crude oil is linearly correlated with pressure. Higher pressure effectively increases the solubility of CO2, reaching 49.1 m3/m3 at a saturation pressure of 10.0 MPa, thus facilitating oil expansion and viscosity reduction. Meanwhile, crude oil saturated with CH4 still retains the capacity to further dissolve additional CO2, reaching 24.5 m3/m3 of incremental CO2 solubilization at 10.0 MPa, and the hybrid effect of CO2 and CH4 reduces oil viscosity to 1161 mPa·s, which is slightly lower than the pure CO2 dissolution case. Temperature increases suppress solubility but promote molecular diffusion, allowing CH4 and CO2 to maintain a certain solubility at high temperatures. In terms of dynamic dissolution and diffusion, the initial CO2 dissolution rate is high, reaching 0.009 m3/(m3·min), the mid-term dissolution rate stabilizes at approximately 0.002 m3/(m3·min), and the dissolution capability significantly decreases later on. CO2 exhibits high molecular diffusion capability in gas-saturated crude oil, with a diffusion coefficient of 8.62 × 10−7 m2/s. For CO2 huff and puff, oil production is positively correlated with the CO2 injection rate and the cycle injection volume; it initially increases with the extension of the soak time but eventually decreases. Therefore, the optimal injection speed, injection volume, and soak time should be determined in conjunction with reservoir characteristics. During the huff and puff process, the bottom hole pressure should be higher than the bubble point pressure of the crude oil to prevent gas escape. Moreover, as the huff and puff cycles increase, the content of saturates in the oil rises, while those of aromatic, resin, and asphaltene decrease, leading to a gradual deterioration of the huff and puff effect. This study provides a comprehensive reference method and conclusions for studying the fluid property changes and enhanced recovery mechanisms in medium to deep heavy oil reservoirs with CO2 huff and puff. [ABSTRACT FROM AUTHOR]

The phenomenon of pore blockage caused by injected suspended particles significantly impacts the efficiency of water injection and production capacity release in offshore oilfields, leading to increased additional resistance during the injection process. To enhance water injection volumes in injection wells, it is essential to quantitatively study the additional resistance caused by suspended particle blockage during water injection. However, there is currently no model for calculating the additional resistance resulting from suspended particle blockage. Therefore, this study establishes a permeability decline model based on the microscopic dispersion kinetic equation of particle transport. The degree of blockage is characterized by the reduction in fluid volume, and the additional resistance caused by particle migration and blockage during water injection is quantified based on the fluid volume decline. This study reveals that over time, suspended particles do not continuously migrate deeper into the formation but tend to deposit near the wellbore, blocking pores and increasing additional resistance. Over time, the concentration of suspended particles near the wellbore approaches the initial concentration of the injected water. An increase in seepage velocity raises the peak concentration of suspended particles, but when the seepage velocity reaches a certain threshold, its effect on particle migration stabilizes. The blockage location of suspended particles near the wellbore is significantly influenced by seepage velocity and time. An increase in particle concentration and size accelerates blockage formation but does not change the blockage location. As injection time increases, the fitted injection volume and permeability exhibit a power-law decline. Based on the trend of injection volume reduction, the additional resistance caused by water injection is calculated to range between 0 and 3.85 MPa. Engineering cases indicate that blockages are challenging to remove after acidification, and the reduction in additional resistance is limited. This study provides a quantitative basis for understanding blockage patterns during water injection, helps predict changes in additional resistance, and offers a theoretical foundation for targeted treatment measures. [ABSTRACT FROM AUTHOR]

Viscoelastic surfactants (VESs) are critical components of water-based fracturing fluids. However, the challenges related to the large volumes and complex disposal of flowback fluids from conventional VES fracturing fluids remain unresolved. Accordingly, a multifunctional small molecule surfactant gel was successfully prepared in this study. This system exhibits the capacity of in situ gel-breaking and converting it into an oil displacement agent, thus achieving the goal of no fluid return. The gel was composed of erucic acid amidopropyl betaine (EAPB), oleic acid amidopropyl betaine (OAPB), and a thickening agent, and the system was referred to as EOO. On the basis of this gel system, a series of performance parameters have been evaluated through extensive experiments. The research results demonstrated that this gel exhibits good stability, viscoelasticity, sand-carrying capacity, and remarkable self-repairing ability at high shear rates. Additionally, the gel achieves ultra-low interfacial tension and wetting reversal characteristics, both of which are conducive to enhanced oil recovery. Oil displacement and profile control of the gel were evaluated using single and parallel core flooding experiments. The results indicated that the EOO gel increased injection pressure in high-permeability cores and mobilized residual oil in low-permeability cores, thereby expanding the swept volume and enhancing recovery. The small molecule gel developed in this study which can be converted in situ into an oil displacement agent is a candidate for enhanced oil recovery in low-permeability oil fields. [ABSTRACT FROM AUTHOR]

The article discusses the problems of developing and justifying a strategy for the geological study and preparation of oil reserves from marginal oil and gas fields in the Caspian sector of Azerbaijan. The scientific works of domestic and foreign scientists studying issues related to the use of subsoil containing volumes of recoverable reserves, located in difficult geological and field conditions and located in remote, inaccessible areas with poorly developed infrastructure, are presented in detail. In addition, unclaimed oil reserves have been scientifically analyzed to determine the industrial significance of the objects and to determine the conditions for the profitable development of marginal offshore fields. [ABSTRACT FROM AUTHOR]

The purpose of this study is to propose a methodology for determining the critical flow rate in flowing wells to prevent the collapse of the productive formation, taking into account the homogeneity of the rocks. The method of operating wells, in which the rise of hydrocarbons from the bottom of the well to the surface occurs due to natural (reservoir) energy, is called flowing. Flowing of oil wells occurs due to hydrostatic pressure or the energy of compressed gas, as well as due to the energy of compressed rocks. The influx of oil to the bottom of wells occurs due to the difference between reservoir and bottomhole pressure. In the case when the pressure of the liquid column (to the wellhead of the filled well) is less than the reservoir pressure, the well will flow. Flowing well production is a method of hydrocarbon production in which the pressure in the formation is high enough to cause the product (such as oil or natural gas) to spontaneously rise to the surface without the additional use of artificial pumps or other devices. Basic concepts of flowing include: 1. Hydrostatic head: The natural pressure created by the hydrostatic column of fluid in a formation allows production to rise to the surface. 2. Compressed Gas Energy: In some cases, the presence of compressed natural gas in the formation can provide additional energy to lift production. 3. Energy of compressed rocks: During fracturing or other geological processes, additional dynamic conditions may be created that promote flow. The influx of oil or gas to the bottom of wells occurs due to the pressure difference between the formation and the bottom. When reservoir pressure exceeds pressure at the bottom, this can lead to flowing - raising production to the surface. Maintaining flowing conditions can be an important aspect of well operation, and engineering efforts may include pressure control, calculations of optimal production rates, use of water injection techniques (If there is water in the formation), and other techniques to ensure efficient production. Most often, in the flow of wells the gas contained together with oil in the formation plays the main role, including in cases where the gas under reservoir conditions is completely dissolved in oil and a homogeneous liquid moves through the formation. The structure of productive formations can be different, including layered and heterogeneous formations. This can lead to uneven hydrocarbon production and problems with water cut in permeable layers. For successful oil or gas production from such reservoir formations, the difference between the reservoir pressure and the pressure at the bottom of the well plays a key role. If the pressure in the liquid column is lower than the reservoir pressure, the well may begin to flow. Often the gas contained together with oil in the formation plays an important role in the flow of wells. Even if gas is completely dissolved in oil and a homogeneous liquid moves through the reservoir, its presence can significantly affect the pressure and dynamics of production. For example, when the pressure at the bottom decreases, gas can be released from the solution, increasing the volume and pressure inside the well and promoting its flow. Effective management of the production process includes not only pressure control, but also evaluation of gas factors, optimization of production rates and use of water injection technologies to minimize the negative effects of heterogeneity of formations and ensure the most efficient production of hydrocarbons. Flowing of an oil well can occur depending on the operating mode of the energy source, including hydrostatic pressure or expansion energy of the gas contained in the oil. In some cases, gushing can occur simultaneously due to both energies. Hydrostatic pressure created by the column of oil and other fluids in the formation can be the main source of energy for a blowout. If the formation pressure is high enough and has good permeability, oil can rise to the surface under the influence of this pressure. If the oil contains dissolved gas, its release and expansion when reaching the surface can also contribute to blowout. Gas expansion creates additional pressure inside the well, which can increase the flow of oil and gas to the surface. When both of these mechanisms operate simultaneously, this can lead to more intense flowing and increased hydrocarbon production. However, control over this process is important to avoid unwanted consequences such as oil spills or loss of hydrocarbons into the environment. In this context, engineers and well operators actively monitor and adjust production parameters to ensure safe and efficient operation. [ABSTRACT FROM AUTHOR]

In the article, the study of the factors affecting the reduction of the oil yield of the oil fields located in the dry areas of Azerbaijan and in the final stage of development and the presence of large amounts of residual oil reserves in those fields are explained. At the same time, the problems of solving probes based on the application of modern innovative technologies and "smart" reagents for increasing oil production from those fields were explained with scientific and practical approaches. [ABSTRACT FROM AUTHOR]

In the article, the analysis of the factors affecting the reduction of oil production in the hydrocarbon fields of the republic, which are in the last period of development, and the analysis of the existing problems in the exploitation of those fields are given. At the same time, referring to the scientific researches and actual oil field products, the sources of attracting investment in the production of residual oil reserves that can be extracted from the deposits, the importance of the development and application of innovative techniques and technologies, the use of the research work of scientists and specialists of scientific institutions in solving problems related to the intensification of oil production. ways and solutions of the state's problems were explained. [ABSTRACT FROM AUTHOR]

The oil or petroleum industry is among the most significant world industries and plays a decisive role in economic and political interactions due to its strategic importance. This massive industry has significantly been influenced by instabilities, political unrests, and sudden price fluctuation in recent years. Additionally, the decision-making process in the oil SC has become a challenging issue because of the presence of considerable facilities in the oil fields, oil refining, and distribution of petroleum products. Hence, the integrated optimization of oil SC has been quite popular with researchers. On the other hand, since there are environmental requirements, people have their shares in the extension of this industry, and developmental planning should consider ecological and social issues. The effort has been made in this article to propose a mathematical programming model for the design of oil supply chain network to reduce their environmental effects and improve the social indices while saving costs. Then, the model was solved with actual data from a real case study of the Iran Oil Industry. Finally, some recommendations have been provided based on analyses of the numerical results. [ABSTRACT FROM AUTHOR]

The Gulf of Suez, which contains Egypt's oldest oil fields, is one of North Africa's most well‐known oil regions. There are more than 80 conventional oil fields in Egypt's Gulf of Suez, some of which have reservoirs that stretch back to the Precambrian and Quaternary. In close proximity to the southern entrance of the Gulf of Suez is the Tawilla West oilfield. The oil field Tawilla West is believed to consist of rotating fault blocks that descend in a south‐west direction. The main producing reservoirs are the Miocene section reservoirs, the Belayim and Kareem sandstones. The current research is focusing on the structural elements affecting this giant field to update the field structural model using the newly processed 3D seismic survey, the acquired data from newly drilled wells and the associated different logging techniques. The seismic information quality varied from poor to fair. The quality of the interpreted stratigraphic horizons and geological faults was mainly controlled by the seismic information quality. The research used seismic attribute analyses to improve interpretation and incorporate additional features, enabling better hydrocarbon potential identification and characterization of the reservoirs. Several geological structure contour maps and cross‐sections were generated to help in delineating and understanding the reservoir's extension. Based on the detailed correlation study, we were able to detect the faults that affected the structure of the Tawilla West field in detail, define their throw amounts and directions, and identify the missed sections across the studied area. This study introduces an updated model scenario to show the differences and their effect on the field development plan and recommendations. By examining subsurface geologic structural characteristics and evaluating petrophysical data, a 3D static reservoir model was created to resolve structural settings and hydrocarbon trapping, providing detailed information on the field and identifying new opportunities for future development. The research discovered that the updated detailed 3D structural model may support the Kareem Reservoir development plans and encourage drilling, workover and dynamic operations to assign development possibilities in the correct area. According to the established model, there are at least three options in the study's attic areas that might boost oil output and oil reserves for the field while avoiding further failures. [ABSTRACT FROM AUTHOR]

Trends are common in regionalized variables, and geostatistical techniques are employed to model these trends, handle non-stationarity, and reduce uncertainty in models. Given the subjectivity involved in modeling and incorporating trends, it is crucial to have tools to identify and improve their inclusion during model development. This study proposes a method to evaluate the significance of trends in geostatistical models. A reference distribution of trend variances derived from stationary unconditional simulations is used to assess the significance of a trend calculated from the available data. Compared to the reference distribution, the trend variance value generates a parameter that offers a quantitative approach to evaluating significance. This parameter indicates the trend's ability to reduce uncertainty in the modeling process. A trend significance classification was established using synthetic variables and validated with various images, including digital elevation models and geological environments (satellite images, seismic data, and outcrop images), covering contexts related to environmental, mining, and petroleum applications. An example from these images was chosen as a case study to demonstrate the potential for reducing uncertainty when incorporating a significant trend in geostatistical models. The significance classification tool enhances understanding of the impact of trends on modeling, particularly regarding uncertainty reduction. It is important to note that more precise models are critical for making more assertive decisions that have significant economic impacts on urban planning projects, petroleum field developments, and mining operations. [ABSTRACT FROM AUTHOR]

The management of oil-contaminated water and wastewater in the oil industry remains a critical challenge due to its environmental and economic implications. This manuscript provides a comprehensive review of separation and removal techniques for oil from water and wastewater. It gives an overview of the origins and compositions of oil in wastewater, including natural and anthropogenic sources, as well as variations in physical states such as free, emulsified, and dissolved oil. The review delves into various separation methods, ranging from traditional gravity-based techniques to advanced technologies like membranes and recent developments in wastewater treatment systems. Furthermore, it discusses the application of new technologies specifically designed for the unique challenges faced in Middle East oil fields. The manuscript explores factors influencing oil-water separation efficiency, including operating conditions, chemical additives, equipment design, and environmental considerations. Additionally, it highlights current aspects and future directions in oily wastewater treatment, emphasizing the need for sustainable and effective solutions in the oil industry. [ABSTRACT FROM AUTHOR]

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