IntroductionSalivary stones, or sialoliths, are calcified concretions forming within salivary glands and their ducts through a two-stage process: an initial formation of a central core via precipitation of inorganic material mediated by organic substances, followed by layering of additional organic and inorganic material. Substrates for sialolith formation include mucoid agglomerates, organic vesicles, foreign bodies, and bacterial biofilms. Understanding the detailed structure of sialoliths may aid in developing specific preventive or therapeutic strategies.Materials and methodsThis study analyzed 137 sialoliths from 102 patients treated across three university hospitals. Stones were extracted via sialendoscopy, direct extraction, or spontaneous extrusion. Structural and compositional analyses were conducted using scanning electron microscopy (SEM-EDX) and x-ray diffraction (XRD).ResultsMost sialoliths were from the submandibular gland (82%), with the remainder from the parotid gland (18%). Parotid stones predominantly exhibited irregular shapes, while submandibular stones were generally ellipsoidal. All stones demonstrated an oolitic structure characterized by a central core surrounded by concentric layers and frequently associated with bacteria. Mineral composition predominantly included octacalcium phosphate (OCP), hydroxyapatite, and whitlockite. Larger sialoliths exhibited a higher proportion of hydroxyapatite, indicating increased crystallinity compared to OCP.DiscussionDespite diverse origins and locations, sialoliths share common morphological and compositional traits. Their formation begins with heterogeneous nucleation of calcium phosphates around organic spherules, likely induced by bacterial biofilms. These initial nuclei aggregate into a central core upon which additional layers of organic and inorganic materials deposit progressively. This layering increases the size and crystallinity of the sialoliths over time. The coexistence of amorphous phases and structural heterogeneity within layers explains the variability among stones. Detailed SEM-EDX analysis supports a unified conformational model for sialoliths that integrates the interplay of organic substrates, inorganic minerals, bacterial biofilms, and temporal factors.ConclusionsSialoliths are oolitic aggregates featuring a central core surrounded by concentric layers composed of organic and inorganic materials. Their formation process involves initial heterogeneous nucleation, bacterial influence, and progressive crystallization. This universal conformational model effectively describes sialolith formation irrespective of patient-specific or anatomical variations.
The texture and composition of river sediments are key to understanding the characteristics of source rocks, chemical weathering in the source area, physical modifications during transport, and human impacts within watersheds. This study analyzes 47 very fine to coarse size sands from the Lancang (Upper Mekong) River in China to monitor compositional variations and assesses the contribution of different geological units to trunk-river sediments. Lancang River sands are mostly feldspatho-quartzo-lithic in composition, with quartz content increasing downstream at the expense of lithic fragments (especially of carbonate lithics). Sand is mostly generated from the Lincang and Baoshan blocks, with subordinate contributions from the Simao and Changdu blocks. This study provides new insights into erosional and depositional processes in the Lancang River and emphasizes the impact of human activities on river sediment transport.
Mohammad Reza Esmaeilinasab, Mastaneh Hajipour, Abbas Shahrabadi
et al.
Abstract Smart water injection into oil fields is an efficient EOR method but has significant challenges due to incompatibility between the formation brine and the injecting water. The presence of reactive ions in smart water can change the wettability of reservoir rock to increase oil production. However, the possibility of formation damage due to inorganic scales may increase. In this research, static and dynamic experiments were conducted to investigate the competition between rock wettability alteration and formation damage due to smart water injection. The experiments were performed in two parts including waters compatibility tests and rock wettability measurements for various concentrations of potential-determining ions in smart water. The crystal size and morphology of the sulfate scales were inspected visually using scanning electron microscopy images. In static compatibility tests, the maximum amount of sulfate scales was detected in the mixture containing 40% injection water. The experimental data indicated that the simultaneous increase in the concentration of sulfate and magnesium ions improves the carbonate rock wettability 18% more compared to increasing sulfate concentration alone. As a result, SW_1Ca.2 Mg.1.5S revealed the highest effect on rock wettability changes from oil-wet to water-wet conditions in both static and dynamic tests. The formation damage analysis through core-flooding experiments showed that increasing the concentration of sulfate ions twice the sea water causes an 88% reduction in core permeability. However, doubling the magnesium concentration in the presence of sulfate ions reduces the permeability decline to 77%. The maximum recovery factor (i.e., 35%) was attained by injecting SW_1Ca.2 Mg.1.5S into the carbonate core, and core permeability was enhanced twofold. The findings show that simultaneous changes in the concentration of potential-determining ions in smart water, in addition to increasing oil production, also prevent formation damage, which is often neglected in previous studies.
The Chang 7 black shale in the Upper Triassic Yanchang Formation is the principal source rock of Mesozoic oil-bearing system in the southwest Ordos Basin, containing high abundances of organic matter and hydrocarbon potential. Our study discusses the role of lake-bottom hydrothermal activities in the enrichment of organic matter during the deposition of the Chang 7 black shale. A large number of basement faults developed in the interior and margin of the Ordos Basin, which provided channels for the upwelling of deep hydrothermal fluids. Moreover, the strong tectonic activities during the Chang 7 sedimentary period provided dynamic conditions for the activation of the faults and the upwelling of hydrothermal fluids. The occurrence of hydrothermal activities in the Chang 7 sedimentary period is proved by the evidences of mineralogy petrology, stable isotopes, major, and trace elements in the black shale. Abundant nutrients that were transported from the lake-bottom hydrothermal fluids into lake water promoted the lacustrine surface primary productivity, and then increased the supply of sedimentary organic matter. At the same time, the degradation of a large number of organic matters increased consumption of oxygen in the water column, resulting in the formation of bottom-water anoxic environments. The accumulation of organic matter in sediments was controlled by the lake-bottom hydrothermal activities by the means of increasing the lacustrine surface paleoproductivity and promoting the formation of anoxic environments.
Recently, subsalt exploration in the Tarim Basin has been one of the most significant targets of the deep hydrocarbon exploration.The Lower Cambrian Xiaoerbulake Formation is the major reservoir in current exploration.However, the analysis of the detailed geochemical and paleoenvironmental characteristics are limited in Keping area in absence of studies in the interior of the basin.This paper focuses on the Well Shutan-1 in the Bachu Uplift of the northwestern Tarim Basin.Based on the analysis of petrology and the geochemical characteristics (major, trace, rare elements and carbon-oxygen isotope), depositional environment of the Lower Cambrian Xiaoerbulake Formation is explored.Our study indicates that the lower, middle and upper part of the Xiaoerbulake Formation in Well Shutan-1 comprise thick algal dolomite, mudstone interbedded with dolomitic limestone and fine to silty dolomite, respectively.The average value of Lan/Ybn is 1.09 in the Xiaoerbulake Formation, of which the lower and upper part show positive Eu anomaly.Silica cementation, silica fragment and dissolution can be seen in the thin section, indicative of hydrothermal influence.Redox-sensitive trace elements are enriched in the middle of the formation.V/Cr and Ni/Co range from 2 to 4.25 and 5 to 7.The grain size of the sediment is finer.These are indications of suboxic bottom-water condition.The RSTEs and their ratios are relatively low in the upper and lower Xiaoerbulake Formation.The grain size of sediment is coarser.These are indications of oxic bottom-water condition.The carbon isotope ranges from -1.3‰ to 2.7‰. It decreases firstly and then increase throughout the interval.Two positive and one negative isotope excursion are identified in the lower and middle part of the interval, respectively.Paleoenvironmental reconstructions indicate that paleo-salinity firstly increased and then decreased.Paleo-seawater temperature gradually increased.Dolomite reservoirs were well developed in the late stage due to moderate salinity, occurrence of algal dolomite along with later weathering and dissolution.The research results can provide a basis for oil and gas exploration in this area.
Geology, Engineering geology. Rock mechanics. Soil mechanics. Underground construction
Abstract Loss of drilling fluid commonly known as mud loss is considered as one of the critical issues during the drilling operation as it can cause severe formation damage. To minimize fluid loss, researchers introduced numerous additives but did not get the expected result. Recently, the use of nanoparticles (NPs) in drilling fluid gives a new hope to control the fluid loss. A basic KCl–Glycol–PHPA polymer-based mud is made, and six different concentrations of 0.1, 0.5, 1.0, 1.5, 2.0, 3.0 wt% iron (III) oxide or Hematite (Fe2O3) NPs are mixed with the basic mud. The experimental observations reveal that fluid loss of basic mud is 5.9 ml after 30 min and prepared nano-based drilling mud results in a less fluid loss at all concentrations. Nanoparticles with a concentration of 0.5 wt% result in a 5.1 ml fluid loss at the API LTLP filter press test. On the other hand, nanoparticles with a concentration of 3.0 wt% enhance the plastic viscosity, yield point, and 10 s gel strength by 15.0, 3.0, and 12.5%, respectively. The optimum concentration of hematite NPs is found to be 0.5 wt% which reduces the API LPLT filtrate volume and filter cake thickness by 13.6 and 40%, respectively, as well as an improvement of plastic viscosity by 10%.
Mohamed Ragab Shalaby, Muhammad Izzat Izzuddin bin Haji Irwan, Liyana Nadiah Osli
et al.
Abstract This research aims to conduct source rock characterization on the Narimba Formation in the Bass Basin, Australia, which is made of mostly sandstone, shale and coal. The geochemical characteristics and depositional environments have been investigated through a variety of data such as rock–eval pyrolysis, TOC, organic petrography and biomarkers. Total organic carbon (TOC) values indicated good to excellent organic richness with values ranging from 1.1 to 79.2%. Kerogen typing of the examined samples from the Narimba Formation indicates that the formation contains organic matter capable of generating kerogen Type-III, Type-II-III and Type-II which is gas prone, oil–gas prone and oil prone, respectively. Pyrolysis maturity parameters (Tmax, PI), in combination with vitrinite reflectance and some biomarkers, all confirm that all samples are at early mature to mature and are in the oil and wet gas windows. The biomarkers data (the isoprenoids (Pr/Ph), CPI, isoprenoids/n-alkanes distribution (Pr/nC17 and Ph/nC18), in addition to the regular sterane biomarkers (C27, C28 and C29) are mainly used to evaluate the paleodepositional environment, maturity and biodegradation. It has been interpreted that the Narimba Formation was found to be deposited in non-marine (oxygen-rich) depositional environment with a dominance of terrestrial plant sources. All the analyzed samples show clear indication to be considered at the early mature to mature oil window with some indication of biodegradation.
Abstract The effect of alkali on immiscible alkali–surfactant (AS) flooding is studied by injecting surfactant individually and surfactant along with alkali. First, reservoir core samples were characterized with the help of X-ray diffraction (XRD), scanning electron microscope (SEM) and thin slide analysis. Based on the clay content of the reservoir, surfactant was selected. Second, AS formulations were designed through dynamic interfacial tension (IFT) and wettability alteration analysis. Third, adsorption of surfactant on porous media was studied with or without alkali to find out the amount of surfactant adsorbed along with the isotherm mechanism. Fourth, core flooding experiments were conducted to find out the recovery efficiency after secondary brine flooding. XRD, SEM and thin slide analysis showed the presence of kaolinite, smectite, illite, silica, quartz in the rock sample. Based on the clay types, sodium dodecyl sulfate (SDS) was selected as surfactant for this study. Ultra-low dynamic IFT in the range of 10−3 was observed with SDS. Addition of alkali further reduced the IFT of the system. Initially, wettability of the reservoir under study was toward water wet, but during AS flooding it was altered to strongly water wet. Adsorption of surfactant on the porous media was reduced by the application of alkali. During secondary brine flooding, maximum recovery was found to be 49% of Initial Oil in Place. Another 14% of residual oil after secondary flooding was achieved by AS flooding.
Abstract Horizontal well has been widely used for heavy-oil recovery in the petroleum industry. Besides, superheated steam has been proved effective in heavy-oil recovery by field practice. In this paper, a numerical model is established with the help of numerical simulator. The effect of bottom water on the productivity of cyclic superheated steam stimulation well has been studied. Some interesting findings show that: (a) the bottom water-channeling phenomenon becomes more severe when the horizontal well is approaching the bottom water. (b) The cyclic oil production fluctuates with periodic number when the horizontal well is close to the bottom water due to the fact that the injected water has an elastic push action on the bottom water. (c) A larger-bottom water size is able to supply a larger elastic energy. While the cyclic oil production of large-bottom water size for the first few cycles is smaller than that with a small-bottom water, it may be turned over for the last few cycles.
Khaled Z. Abdelgawad, Mahmoud Elzenary, Salaheldin Elkatatny
et al.
Abstract The equivalent circulation density (ECD) is a very important parameter in drilling high-pressure high-temperature and deepwater wells. ECD is a key parameter during drilling through formations where the margin between the pore pressure and the fracture pressure (FP) is narrow. In these critical formations, the ECD is used to control the formation pressure and prevent kicks. Recent approaches in oilfields to determine ECD depend mainly on using expensive downhole sensors for providing real-time values of ECD. Most of these tools have operational limitations such as high pressure and high temperature which may prevent using these tools in downhole conditions. The objective of this paper is to develop a new approach for predicting ECD using artificial intelligence (AI) techniques from surface drilling parameters [mud weight, drill pipe pressure, and rate of penetration (ROP)]. 2376 data points were used to develop the AI models. The data were collected during the drilling of an 8.5″ vertical hole section. Two AI models were used to estimate the ECD: artificial neural network (ANN) and adaptive neuro-fuzzy inference system (ANFIS). An empirical correlation for ECD was derived from the optimized ANN model by extracting the weights and biases. The developed ANN and ANFIS models were able to calculate ECD with a correlation coefficient (R) of 0.99 and average absolute percentage error of 0.22% for ANN and ANFIS models, respectively. The developed empirical correlation for the ANN model can be used during well design to choose a correct mud weight to safely drill the well based on the expected drilling parameters. It will also minimize the drilling problems related to ECD such as losses or gains especially in critical situations where the margin between the pore and fracture pressure is very narrow. In addition, using this technique will save cost and time by reducing the need for expensive, complicated downhole tools.