Arabian Journal of Geosciences最新文献

Urmia Lake (UL), one of the most important saline ecosystems in the world, has faced a severe water level drop in the last two decades. In this research, the seasonality of precipitation in the Urmia Lake basin (ULB) was analyzed using the daily precipitation data of 30 rain-gauge stations in the period 1991–2018. The occurrence time of extreme precipitation (OTEP) was determined by using circular statistics. The uniformity of OTEP was examined by Rayleigh test (RT) and Kuiper test (KT). The slope of the trend lines for the OTEP was estimated using the modified Sen’s estimator. Trends in the OTEP were analyzed by the non-parametric Mann–Kendall test. The results indicated no uniformity in the OTEP at 0.1, 0.05, and 0.01 levels in the basin. Seasonal events throughout the year were divided into two separate seasons denoted by S1 for late winter and early spring and S2 for autumn. The results showed that the mean seasonality increased from 0.3 to 0.82 (for S1) and 0.9 for S2. The comparison of seasonal strength in the west and east parts of ULB revealed that these two parts of ULB had the same seasonality strength (SS) in the S1. However, the seasonality of the western part of the lake was stronger than the eastern part in S2. Trends in OTEP showed that about 60% of the stations witnessed upward trends in S1. This was about 27% in S2. The findings of this analysis can provide useful information about the changes in the OTEP and its hydrological impact on the studied basin. This information is helpful in the scientific management of water resources in the Urmia Lake basin.

Sediment samples from the Mugheb River in Bamenda were analyzed by inductively coupled plasma-optical emission spectrometry to determine their major, trace, and rare earth element contents, so as to ascertain their provenance, paleoweathering, and tectonic setting. The enrichment of Fe₂O₃ suggests these are derived from hematization of basaltic rocks. Significant SiO₂ content recalculated to an anhydrous basis and adjusted to 100% (SiO_2(adj)) indicates the abundance of quartz and kaolinite in sediment samples. Enrichment of transition elements relative to the reference values indicates mafic source rocks. The rare earth element patterns indicate negative Eu (Eu/Eu* = 0.54–0.82) and positive Ce (Ce/Ce* ~ = 1.04–1.67) anomalies, suggesting that they were derived by fractionated mafic rocks and, to a little extent, by fractionated felsic rocks. The chemical index of alteration (CIA) and plagioclase index of alteration (PIA) indicate intense weathering in the source area in a hot humid climate reflected by the removal of labile cations relative to stable residual constituents, which corroborate with the climate of the Cameroon. The ratios of SiO_2(adj)/Al₂O₃, K₂O/Al₂O₃, and K₂O/Na₂O and the index of compositional variability (ICVn) indicate compositionally mature sediments in which sediment samples experienced recycling and noticeable effect of sorting and reworking. The river sediments are deposited in oxic conditions within the riverine environment. The sediments were sourced dominantly from mafic and little contributions from felsic sources, and represent mature recycled detritus. Tectonic discrimination diagrams suggest that Mugheb River sediments were derived from rock types, which represent a passive continental margin, which is consistent with several tectonic history models of the Cameroon Volcanic Line and the Pan-African fold belt.

Pressure on land is a consequence of population expansion, increased food consumption, and competition between land uses. Soils play a crucial role in supporting food production and providing ecosystem services. The demand for timely and relevant soil information that can support decision-making at different scales is increasing as efforts are made to ensure sustainable use of soil resources. Digital soil mapping (DSM) has become increasingly popular in various ecosystems, including arid, semi-arid, and humid regions, as well as rangelands and forests, due to its ability to overcome associated constraints to traditional methods of soil mapping. DSM offers a more efficient way to provide soil information in terms of time and cost, while improving map accuracy and providing quantified estimates of uncertainty. DSM involves the construction of soil spatial information systems using numerical models to analyze spatial and temporal variations in soil types and attributes based on soil observations, knowledge, and associated environmental factors. The main objective of this article is to present an overview of advances in thematic soil mapping in relation to advances in remote sensing (RS). First, we provide a brief summary of common tools used in DSM. Subsequently, we discuss advances in historical soil data, environmental variables, and applications of DSM tools. Finally, we present the major developments and future perspectives suggested by existing research. In conclusion, although DSM is becoming increasingly sophisticated to meet diverse soil information requirements, there are still issues to be addressed, particularly in highly heterogeneous and human-impacted environments. These issues require the development of new methodologies and applications of the DSM.

Determining the permeability of the reservoir in the absence of well logs and core analysis data is a challenge in the oil and gas industry. Even though correlations such as Winland and Pittman exist, they often fail to provide an accurate permeability value. This study utilized the mercury injection capillary pressure data from published literature to determine the permeability in sandstone reservoirs. The dataset included parameters such as pore throat radius at various mercury saturations (25%, 35%, 50%, and 75%), along with permeability and porosity determined through laboratory experiments. Different machine learning techniques, namely, LASSO regression, ridge regression, support vector regression (SVR), random forest (RF) regression, decision tree (DT) regression, K-nearest neighbor (KNN) regression, gradient boosting, Ada Boost, and multilayered perceptron (MLP) were used to determine permeability values form porosity, pore throat radii, and pore throat sorting data. Sixty-three samples were randomly divided into training and test sets, out of which 75% were used for training both the models while 25% were used to test them. The regression coefficients suggested that pore throat radius at 75% saturation (r75) had the highest influence on the permeability values, followed by porosity (phi) and r50. It was noted that as the learning rate increased, the root mean squared error (RMSE) gradually reduced from 48.9208 to 47.2889 for ridge and LASSO-normal, while for ridge and LASSO-polynomial 99.97 to 52.2629. Various models and correlations have been developed in previous studies; however, the lithological characteristics of reservoir rock vary with location and subsurface factors. The novelty of this study lies in its integration of machine learning models with mercury injection capillary data for accurate permeability predictions, addressing the limitations of traditional correlations and offering a reliable method for characterizing sandstone reservoirs in the absence of well log data and evaluating the flow behavior of reservoir fluids within the porous media.

A great number of variables (such as rock properties, in-situ stresses, drilling fluid, inclination etc.) are effective on wellbore stability and the combined effect of those variables determines the stability condition of wellbore. The main aim of this study is to analyse the combined effect of drilling fluid, stress state and inclination angle considering that there is no comprehensive study conducted on the topic. In this study, three stress conditions (normal faulting stress condition, reverse faulting stress condition and strike slip faulting stress condition), three drilling fluids (bentonite based, KCl based and polymer based), three inclination angles (0, 45 and 90°) and two depths (2800 and 5000 ft) were considered to evaluate the effect of those parameters on wellbore stability. The results of analyses showed that the number of instabilitity zones around the wellbore increases as the inclination angle increases under normal fault stress state However, number of instability zones are higher for low inclination angle values under reverse and strike slip fault stress states. While the best stability condition was obtained with polymer drilling fluids due to limited decrement on strength properties, the worst stability condition was satisfied with bentonite drilling fluids due to considerable decrement on strength properties as a result of interaction with drilling fluid.

In view of the gas flow problem in the hydraulic fracturing engineering of L-type horizontal well and in the process of gas production in coalbed methane development, the permeability stress test of single fracture coal-rock combination was carried out. The permeability evolution law of fractured coal-rock combination under axial compression, confining compression, and gas pressure is analyzed. The axial compression has little effect on the permeability of coal-rock combination with fractures, and the permeability has no obvious change. Taking 0.25 MPa gas pressure as an example, the permeability of N1 fluctuates between 0.004 and 0.005 mD, and the permeability of N2 and N3 samples fluctuates between 0.002 and 0.0035 mD. With the increase of confining compression, the permeability decreases with the increase of confining compression. Taking the N4 sample as an example, when the gas pressure is 0.50 MPa, the permeability of N4 rapidly decreases from 0.351 to 0.0025 mD. The permeability has decreased by 99.3%. With the increase of gas pressure, the permeability and stress sensitivity of fractured coal-rock combination decrease gradually. In the process of gas pressure loading, the permeability decreases greatly due to the existence of gas slippage effect in the low-pressure stage. When the gas pressure exceeds 1 MPa, the joint action of slip effect and velocity-sensitive effect makes the permeability almost unchanged. Taking the N4 sample as an example, when the axial and confining pressures are 6 MPa, the permeability decays from 1.298 to 0.382 mD, with a decay ratio of 70.6%. Finally, the permeability calculation model of single fracture coal-rock combination under in situ stress and gas pressure can well match the experimental data and clarify the influence of each permeability on the overall permeability. The permeability model shows that the overall permeability depends on the part of the smaller permeability, and the higher permeability only makes the overall permeability increase slightly.

Bakar (Arab J Geosci 14:763, 2021) presented a comprehensive study to answer some questions regarding the origin of cherts and selective silicification of Eocene and Messinian host rocks. Silicification is one of the most significant diagenetic processes influencing the evolution of sedimentary rocks, especially carbonates and evaporites, which makes this study interesting. A large number of sedimentologists, stratigraphers, petroleum geologists, and other related fields are interested in studying silicification owing to the potential information that study of silicification might provide on paleogeography, paleoceanography, stratigraphic correlations, the diagenetic history of carbonate rocks, and other topics. However, I have some comments on some points stated in the paper of Bakar (Arab J Geosci 14:763, 2021).

This study focuses on evaluating the quality of the Aouinet Wanin F3B sandstone as a potential hydrocarbon reservoir in Well A37, NC 169A, Wafa Field, Ghadamis Basin, northwest Libya. Capillary pressure data, a key indicator of pore throat size distribution and fluid percolation capability, is crucial for reservoir characterization. However, due to the high costs, time constraints, and environmental concerns associated with mercury injection capillary pressure testing, this study introduces an alternative approach. We utilize routine core analysis data specifically porosity and permeability to model synthetic drainage capillary pressure curves based on Pittman’s modified equations. Our results reveal three distinct rock types represent the reservoir intervals, categorized into mega-, macro-, and micro-pores. The uppermost zone of mega- and macro-pores demonstrates excellent to good reservoir qualities. The log–log plot of pore throat radius versus permeability using Pittman’s R50 equation yielded a 1 mD permeability cutoff, aligning with common reservoir benchmarks, while the Winland R35 equation produced a cutoff of 0.4 mD, slightly outside the acceptable range which is between 0.5 and 1 mD. These findings offer a cost-effective and reliable alternative for reservoir quality assessment.

Gels that initially exhibit low viscosity and later form a stable three-dimensional structure can be successfully employed in controlling fluid loss during drilling operations. Hybrid gels, composed of a cross-linked polymer gel as the continuous phase and an oil-based fluid as the internal phase, offer a more cost-effective and easily controllable solution than conventional polymer gels. This study investigates the performance of hybrid gels enhanced with nanoparticles (NPs) for controlling fluid loss during drilling operations. To evaluate the impact of environmentally friendly NPs (nano-silica (NS) and nano-bentonite (NB)) on gel behavior, several parameters, including initial and final gelation times (IGT and FGT), crosslinking rate (CR), and final viscosity (FV), were assessed under varying conditions of pH, temperature, and salinity. Additionally, gel stability over time, dynamic stability, and maximum sealing pressure were measured. To assess potential reservoir damage, gel degradation was evaluated in hydrochloric acid solutions with concentrations of 15 wt. % and 28 wt. %. Results demonstrate that NPs significantly enhance the performance of hybrid gels, improving sealing pressure by approximately 20% in fractured and highly permeable porous media. The gels exhibited enhanced stability, resistance to high pressures, and minimal reservoir damage. These findings highlight the potential of hybrid gels with NPs as a promising solution for combating fluid loss and improving drilling efficiency and safety.

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