Hydrogen Index Research Articles

Diseases of the mucous membrane and the activity of the galvanic cell in the oral cavity

AIM. The objective of this study is to determine the frequency of detection of active galvanic cells in the oral cavity in the absence and presence of diseases of the oral mucosa, the development of which may be associated with the irritating effect of direct electric current.MATERIALS AND METHODS. Two groups of 50 patients were examined. All patients had at least 2 metal structures in the oral cavity. The first group comprised patients who had no diseases of the mucous membrane, the second group comprised patients with diseases of the oral mucosa. To detect metal structures that could form a galvanic pair, the electrochemical potential of each metal structure was determined and the difference between the potentials obtained was calculated. To determine the activity of a galvanic element formed by galvanic vapors, the hydrogen index of the gingival fluid in the area of these structures was determined.RESULTS AND DISCUSSION. The difference in the electrochemical potentials of metal structures in the studied groups had no statistically significant differences (p > 0.05) and amounted to 129 + 24.7 mV in the first group, to 135 + 19.8 mV in the second. In the first group, 92 % of patients had no significant difference in the hydrogen parameters of gingival fluid near pairs of metal structures (p > 0.05). The hydrogen values were 6.6 + 0.26 at the cathode and 6.9 + 0.35 at the anode. In the second group, in 88 % of patients, when measuring the hydrogen index of the gingival fluid, a high difference in pH values from 0.7 to 1.5 units was found. The values of hydrogen parameters near the cathode were 7.8 + 0.29, and the will of the anode was 6.3 + 0.22 (p < 0.05).CONCLUSION. Measuring the hydrogen parameters of the gingival fluid near metal structures forming a galvanic pair makes it possible to assess the activity of a galvanic cell. In the absence of diseases of the oral mucosa, the detection rate of active galvanic cells was only 8 %, and in diseases of the mucous membrane, active galvanic cells were detected in 88 % of patients.

Understanding the burial history and the hydrocarbon potential of the late Paleozoic Claromecó foreland Basin (Southwestern Gondwana, Argentina) by combining organic geochemistry, organic petrology, and thermal modeling

The Claromecó foreland Basin (Carboniferous–Permian; southern Buenos Aires province, Argentina) is key to understanding the paleotectonic evolution of the southwestern Gondwana margin and is relevant to energy resource exploration. This study reconstructs the thermal and burial history of the Claromecó Basin by integrating geochemical data, organic petrology, and thermal modeling techniques. Cores samples of the Tunas Formation (Pillahuincó Group, Early Permian) were studied. A 1D thermal model was constructed, calibrated with vitrinite reflectance measurements (VRo %), and corroborated with fluid inclusion and apatite fission track data from previous studies. Rock-Eval pyrolysis results show TOC% values ranging from 0.13 to 60.35 wt%. The Hydrogen index (HI < 50 mg HC/g TOC) and Oxygen index (OI < 50 mg CO2/g TOC) indicate the dominance of Type III and Type IV kerogens, most likely resulting from the thermal maturation of an original Type III kerogen. Petrologic observations confirm the presence of macerals from the inertinite group, as well as minor amounts of vitrinite and liptinite. The Tmax displays a temperature range mostly from 460 to 610 °C. The VRo % values range from 1.5 to 2.0%. Geochemical data combined with VRo % measurements confirm a late catagenesis to metagenesis stage within the wet to dry gas window for coals and organic-rich strata.In order to constrain the thermal evolution of the basin infill, different scenarios were tested by varying the heat flow and the missing section thickness associated with the uplift and erosion of the basin (Permian–Cenozoic unconformity). The best calibration results were obtained with an erosion thickness of 3000 up to 4200 m and paleo heat flow peaks of either 60 or 80 mW/m2 during the Lower Permian–Lower Cretaceous. The Tunas Formation was deposited and buried during the Permian–Triassic (Gondwanides Orogeny phase), reaching a maximum temperature of 180 °C. The results obtained by combining geochemical analysis, organic petrology, and thermal modeling techniques indicate that the coal beds of the Tunas Formation could have a current potential as gas-prone source rocks. Despite that, the hydrocarbon generation capacity of coal levels is currently low due to the high percentage of residual (Type IV) kerogen. Further research could help clarify if the hydrocarbons potentially expelled by these source rocks have been lost due to migration or could be trapped somewhere in the basin.

Unconventional hydrocarbon prospectivity of the Paleoproterozoic Fraynes Formation in Manbulloo S1, Northern Territory

The Paleoproterozoic Fraynes Formation in the Birrindudu Basin is a chronostratigraphic equivalent to the prospective Barney Creek Formation in the McArthur Basin and yet a comparable understanding of its source potential is lacking. As part of Geoscience Australia’s Exploring for the Future program, this study aims to assess the hydrocarbon generating potential and shale gas prospectivity of the Fraynes Formation in the exploration drill hole Manbulloo S1 through the reconstruction of the original source-rock characteristics and well log interpretation. Internal units inside the Fraynes Formation were defined according to sedimentary facies. The hydrocarbon generation potential was estimated from the calculated original total organic carbon content, hydrogen index and thermal maturity data measured from bitumen reflectance data. The shale total porosity was re-interpreted from bulk density logs by removing the organic matter effect, adding organic porosity for the organic-rich shales, and updating the water saturation. The maximum amount of gas generated from the organic-rich source rocks is 3969, 2769 and 1912 Mcf/a-ft assuming the kerogen compositions of 100% Type I, mix of 50–50% Type I and II, and 100% Type II, respectively. The richness of organic matter and interpreted water saturation (&lt;100%) imply favourable shale gas prospectivity in the Fraynes Formation. This work expands our knowledge on the potential unconventional energy resources in the west of the greater McArthur Basin.

РАЗРАБОТКА СОСТАВА И ТЕХНОЛОГИИ ГЛАЗНЫХ КАПЕЛЬ АНЕСТЕЗИРУЮЩЕГО ДЕЙСТВИЯ

In modern ophthalmological practice, the use of local anesthetics for surface anesthesia of the eyeball becomes an integral stage in preparing the patient for diagnostic studies, therapeutic manipulations, surgical and laser interventions. The share of regional pain management methods is steadily increasing. However, at the same time, the list of requirements that local anesthetics must meet is also growing. According to them, the drug that combines high anesthetic activity and minimal toxicity should be considered the best. The local anesthetic anilocaine hydrochloride, developed according to the author's method in PGFA, exhibits high surface anesthetic activity with relatively low toxicity, and also has anti-inflammatory and moderate antimicrobial activity, which distinguishes it very favorably from the local anesthetics used and is an alternative to the use of expensive imported drugs. The purpose of this study is to develop the composition and technology of anesthetic eye drops. Materials and methods. The pharmaceutical substance anilocaine hydrochloride was used as a pharmacologically active component. The determination of the hydrogen index was carried out by the potentiometric method in accordance with the requirements of the OFS "Ionometry". To study the stability of eye drops, characterized by the indicator "Related impurities", a high-pressure liquid chromatograph "ShimadzuLCProminence" (Japan) was used. Statistical processing of the results of chemical studies was carried out according to generally accepted methods using standard EXCEL computer programs. Results and discussion. As a result of the conducted research, the composition of anesthetic eye drops based on anilocaine hydrochloride has been substantiated and developed. A technology for manufacturing eye drops has been developed to ensure the sterility of the resulting form. Conclusion. Based on technological and microbiological studies, the composition and technology of locally anesthetic eye drops based on anilocaine hydrochloride for surface (drip) anesthesia of the eyeball has been developed.

РЕЗУЛЬТАТЫ ОПРЕДЕЛЕНИЯ PH ДЕСНЕВОЙ ЖИДКОСТИ, У ПАЦИЕНТОВ С НЕСЪЕМНЫМИ ПРОТЕЗАМИ, ИЗГОТОВЛЕННЫМИ ТРАДИЦИОННЫМ И ЦИФРОВЫМ МЕТОДОМ

Relevance. Non-removable dentures have an effect on the marginal periodontal of the supporting teeth. An objective criterion for evaluating the periodontal reaction is the hydrogen index of the secreted gingival fluid as the physiological environment of the body, the transudate of blood serum filling the gingival sulcus. The aim of the study was to determine the effect of non–removable prostheses made by traditional and digital methods on the condition of periodontal tissues by measuring the pH of gingival fluid. Materials and methods. To determine the pH of the gingival fluid, special strips of universal indicator paper were used, which allow measuring the pH of the biological fluid in the range from 3.0 to 7.5 units with a minimum step of 0,3. Results. Digital and traditional methods of manufacturing non-removable prostheses are statistically significantly distinguishable with a significance level of p &lt; 0,025 by the pH value of the secreted gingival fluid. Thus, the hydrogen index of gingival fluid in patients with prosthetics using traditional technologies was shifted to a more acidic environment (the median samples differ by 15,4%). Our study made it possible to establish that the hydrogen index of gingival fluid in supporting teeth covered with non-removable dentures made by the digital method is closer to the boundary values of the norm, which indicates their weakly pronounced effect on the condition of the marginal periodontium, due primarily to the smaller thickness of the edge of the artificial crown, which does not have a repelling effect on the gingival margin, unlike from traditional designs with a thicker edge, secondly, the anatomical shape of the prosthesis, which differs little from a natural tooth, and thirdly, significantly less influence of the microbial landscape with a more precise fit of the edge of the artificial crowns to the posterior ledge.

Estimation of original total organic carbon content and hydrogen index using major and trace element concentrations in the overmature Upper Ordovician–lower Silurian Wufeng–Longmaxi marine shales, southeast Sichuan Basin, south China

Estimation of original total organic carbon content and hydrogen index using major and trace element concentrations in the overmature Upper Ordovician–lower Silurian Wufeng–Longmaxi marine shales, southeast Sichuan Basin, south China

Source rock characterization based on geochemical observations using Well BO-1, Central Sumatra Basin

The Central Sumatra Basin, characterized as a tertiary back-arc basin, stands as one of Indonesia’s foremost hydrocarbon-producing basins. Consequently, in the pursuit of hydrocarbon exploration endeavors, a comprehensive analysis of the potential source rocks within this region becomes imperative. The focal point of this study is the BO-1 well, situated within the Pematang Formation. Geochemical analysis methods, specifically leveraging Total Organic Carbon (TOC) and Rock-Eval Pyrolysis data, were employed to assess the quality, quantity, and maturity of the source rock. The research findings reveal a noteworthy organic material content at a fair-to-good level, registering an average TOC value of 0.69% and a Potential Yield of 1,994 mg/g, both falling within the fair-to-good classification. The Hydrogen Index value designates the source rock as type III kerogen, indicating a propensity for gaseous product generation. Maturity evaluation places the source rock within an immature to mature range, with a maximum temperature range of 383-452°C. In summary, the analysis discerns the source rock within the research area as an effective type, characterized by a substantial organic material abundance at a fair-to-good level and a mature maturity level. This conclusion is reinforced by the lithology of the research area, predominantly comprising mudstone, recognized for its richness in organic material.

Vitrinite Reflectance Suppression Revisited

Vitrinite Reflectance Suppression Revisited

Influence of HEM Drilling Fluid on Organic Geochemical Characteristics of Deep-Water Source Rocks in the Qiongdongnan Basin.

The influence of oil-based drilling fluid on the geochemical characteristics of source rocks has been widely reported in the northern South China Sea. However, contamination from water-based HEM drilling fluid has long been neglected in previous deep-water petroleum exploration. To further understand the impacts of HEM drilling fluid on deep-water source rocks, the organic matter abundance and type, kerogen maceral composition, and saturated biomarkers of the deep-water source rocks in the Qiongdongnan Basin were investigated. The influence of HEM drilling fluid on the organic geochemistry data of cuttings is significant but minor for sidecores. It is evident that the organic drilling additives in HEM drilling fluid can increase the organic matter abundance and optimize the organic matter types of shale cuttings. Specifically, the total organic carbon, S1, S2, and hydrogen index are increased by 28.5 ± 6.1, 90.8 ± 2.0, 34.2 ± 2.0, and 51.9 ± 4.0%, respectively. Furthermore, the organic drilling additives will greatly enhance the levels of C29 regular steranes, especially for C29-ααα-20R sterane, with the influence still persisting even when conducting GC-MS-MS analysis. The highly abundant 17α (H) -22, 29, 30-trisnorhopane, 17β (H)-22, 29, 30-trisnorhopane, C29-3117α (H), 21β (H) hopanes, and C29-31 17β (H), 21α (H) hopanes may directly originate from the organic drilling additives. It is dangerous to directly use organic geochemical data from deep-water source rock cuttings contaminated by HEM drilling fluid as it may lead to conclusions that are entirely inconsistent with the basin's geological background.

Organic geochemical characteristics of the Late Cretaceous coal and carbonaceous shale succession from the Taranaki Basin, New Zealand: Implications for sedimentary environmental setting and petroleum generation potential

This comprehensive study investigates the organic matter characteristics within the Late Cretaceous Rakopi and Taniwha formations, based on data from four exploration wells situated in New Zealand's Taranaki Basin. It employs a multifaceted approach, integrating bulk geochemical analyses, biomarker measurements and carbon isotopes to unveil the geological history of these formations. Analytical results include total organic carbon content, ranging from 7.27 to 75.78 wt%, and generation potentials spanning from 28.24 to 309.16 mg hydrocarbon/g rock. These observations underscore the source rock potential of these Late Cretaceous strata. These rocks show a mixed organic matter of hydrogen‐rich Type II and Type II/III kerogens, as evidenced by hydrogen index values (HI) between 237 to 428 mg hydrocarbon/g rock. These formations demonstrate promise potential for both oil and gas generation. Biomarker analysis uncovers distinct signatures, featuring a pristane/phytane (Pr/Ph) ratio ranging from 3.27 to 10.91, a Tm/Ts ratio surpassing 7 and elevated concentrations of C29 regular steranes relative to C27 and C28 regular steranes. These biomarker characteristics suggest a composite organic matter composition, influenced by terrigenous organic matter, likely deposited in oxygenated fluvial deltaic environments. Bulk carbon isotopic data corroborate these findings, highlighting the abundance of terrigenous organic matter. Collectively, these insights reveal that the coal and carbonaceous shale intervals in the examined wells are in the early stages of oil generation. Therefore, the Rakopi and Taniwha formations have not yet yielded commercially viable oil and/or gas quantities. In this case, these formations hold substantial promise for future exploration activities in relatively deep wells, with limited oil expulsion from coals.

Unveiling the petrographical, palynological, palynofacies and geochemical archives of coal and shaly coal deposits in the Mandakini–B block of Talcher Basin: An insight into the paleoecology, depositional environment, kerogen type and source rock potential

Coal and shaly coal beds in the Talcher-Mahanadi Basin, eastern India, belongs to Barakar Formation (Artinskian). A comprehensive analysis was undertaken, including organic petrography, palynology, palynofacies, proximate analysis, Rock-Eval pyrolysis and Field Emission Scanning Electron Microscopy (FE-SEM). The samples consist of the vitrinite group of macerals (avg. 38.2 vol.%), followed by inertinite and liptinite, suggesting peat-forming higher plant vegetation was deposited under prevailing anaerobic conditions. However, the significant presence of inertinite macerals (avg. 29.2 vol.%), including semifusinite and fusinite, along with opaque phytoclasts (avg. 17.3 %), implies occasional shift to oxic conditions. High occurrence of tissue-derived phytoclasts (avg. 64.3 %) indicates that higher plants were the primary contributors to peat formation. Detrovitrinite sub-groups and non-biostructure phytoclasts suggests contributions from herbaceous flora and/or potential tissue degradation due to microbial activity. The palynomorph distribution reveals the dominance of Glossoptriadales, followed by Coniferales and trilete spore groups, comprising 25 genera and 40 species. Non-striate bisaccate pollen, primarily Scheuringipollenites (15–34 %) and sub-dominant striate bisaccate pollen Faunipollenites (11–18 %) prevail in the palynoassemblage. Petrographic indices suggest that the deposition of peat-forming telmatic vegetation has largely occurred in wet forest swamp conditions within the mesotrophic hydrological setting. Palynofacies data, plotted on Tyson’s APP (Amorphous organic matter-Phytoclast-Palynomorph) ternary diagram, suggests suboxic to dysoxic deposition conditions. Low phytoclast preservation index (PPI) indicate proximal deposition of the organic matter. Vitrinite reflectance (VRo%) ranged between 0.42 and 0.68 %, suggesting that the coalification reached up to ‘Medium rank D’ or Bituminous D stage. The substantial total organic contents (TOC: 34.02–61.84 wt.%), hydrogen index (HI) (avg. 154 mg HC/gTOC) and dominance of vitrinite maceral/non-opaque phytoclasts indicate Kerogen Type III and have significant potential for gaseous hydrocarbon generation. FE-SEM images reveal well-developed intergranular and organic pores within the matrix system, serving as both a source and storage in coal beds.

Geochemical and Biostratigraphical Evaluation of Lokpanta Shale in Abakaliki Anticlinorium, Anambra Basin Province, Southeast Nigeria

A geochemical and biostratigraphic method has been applied to explore the quality of organic matter, thermal evolution, potential hydrocarbon source and type of fossils of Lokpanta Shale from the Abakaliki Anticlinorium, Anambra Basin Province, Southeast Nigeria. Data obtained reveal that the total organic carbon (TOC) (2.18wt%) of the shale constitutes that of good to excellent source rock with gas-prone kerogen indicated by Rock-Eval S2/S3 (2.32). The low oxygen index (OI) (27.20 mgCO2g-1TOC) suggest deposition under low energy environments. The plots of HI against Tmax classified the organic matter as Type III kerogen. The poor concentration of OM is thought to account for its current hydrogen index (31.47 mgHCg-1TOC). The predominance of Type III kerogen in the Lokpanta shale suggests their potential to generate gas in the deeply buried sections. The Tmax values from the pyrolysis of the shales of the Lokpanta ranges from 428 to 442oC corresponding to maturity levels within the oil formation. The lamination of the sediments of the Lokpanta area with no burrows and the occurrence of dominantly planktonic foraminiferal assemblages also indicate a quiet water anoxic marine condition.

Evaluation of shale oil and gas plays - Part I: Shale reservoir property modelling of the North Sea Kimmeridge Clay Formation

The Kimmeridge Clay Formation (KCF) forms the source rock for most conventional hydrocarbon accumulations within the UK North Sea. However, only a few previous studies have analyzed the potential of the KCF for unconventional resources (i.e., shale oil and gas).Here, we use machine learning techniques combined with established rock property equations to generate geochemical, petrophysical and geomechanical logs for 16 wells within Quadrant 15 of the Outer Moray Firth, UK North Sea. The neural network models used to generate geochemical logs are trained using the Levenberg-Marquardt backpropagation algorithm. The generated well logs and new KCF depth maps, constrained by an existing Base Cretaceous Unconformity (BCU) map of the UK North Sea and well top information from 48 wells, are used for 3D geostatistical modelling of KCF properties across the area. The resulting KCF property maps allow us to assess the shale oil and gas play potential across the region.Our results suggest good organic richness and hydrocarbon yield potential for the KCF within the study area, with up to 9 wt% original total organic carbon (TOCo), 48 mg/g original hydrocarbon yield (S2o), and 607 mg/gTOC original hydrogen index (HIo). Modelled total porosity values range between 2 and 13%, and brittleness indices lie between 25 and 65%, within the range reported for proven shale oil and gas plays.A sweet spot map, created by integrating our modelled KCF properties, indicates prospective areas for shale oil and gas exploitation within the central Witch Ground Graben, and to a lesser extent areas of the Piper Shelf and Claymore-Tartan Ridge. These areas show good potential based on all investigated properties, with respect to industry standards.

Физико-химические показатели гомогената трутневого расплода, адсорбированного на безлактозных адсорбентах в процессе хранения

Abstract. Drone brood is a product that exhibits high biological activity, so its use can be recommended to a wide range of people as an adaptogenic, actoprotective and antioxidant agent. The high concentration of biologically active substances, such as decenoic acids, unsaturated fatty acids, sulfhydryl groups, sugars, hormones and hormone-like compounds makes drone brood a product very sensitive to environmental factors, which necessitates its stabilization. To stabilize drone brood homogenate, in a number of countries, a lactose-glucose adsorbent is usually used. The relevance of the work is due to the widespread prevalence of lactase deficiency among the population, the prevalence of which among the Eastern Slavs reaches 16–18 %, and among some peoples of Asia, Australia and America exceeds 80 %, which limits the use of adsorbed drone brood using a classical adsorbent containing lactose. The purpose of the work is to develop an innovative product based on drone brood that does not contain lactose as an adsorbent, and to trace the dynamics of the preservation of its biologically active components during storage. Potato starch was used as a lactose substitute in the adsorbent. This product can be recommended to a wider range of consumers. The work used methods for determining the physicochemical parameters of products, such as humidity, oxidation index, hydrogen index, mass fraction of decenoic acids, mass fraction of crude protein, free acidity, acid number, iodine number. The scientific novelty lies in the development of formulations for new products based on drone brood that do not contain lactose and the determination of the optimal product among them in terms of technological and physicochemical parameters. As a result of the studies, it was found that an adsorbent consisting of 80 parts of starch and 20 parts of glucose provides optimal product performance at a ratio of adsorbent to drone brood homogenate of 3 : 1.

Novel insights about petroleum systems from source and reservoir rock characterization, Cretaceous Deposits, Babouri-Figuil Basin, Northern Cameroon

The Babouri-Figuil Basin (BFB) is a frontier basin for petroleum in Cameroon. It belongs to the series of Cretaceous rift basins of the West and Central Rift System (WCARS), the origin of which is related to the opening of the South Atlantic. Within the same rift system, commercial hydrocarbon accumulations have been discovered in Chad, Sudan, Niger and, more recently, in Nigeria (Gongola Basin). The study of the geology of the BFB just recently received considerable attention, mainly because of its presumed hydrocarbon potential. In the pursuit of researching possible petroleum systems in the BFB, the current study provides a first look into the characterization of source and reservoir rock and its integration into a 2D lithostratigraphic model. The study was solely based on outcrop samples. Black shale and massive claystone are good to excellent hydrocarbon source rocks [e.g., up to 38 wt% total organic carbon (TOC), up to 943 mg/g hydrogen index, up to 85 m thickness, up to 20–30 km lateral extension], with moderate to high values of extractable organic matter (e.g., >10,000 ppm). Calcareous claystone, on the other hand, are poor source rocks [e.g., <0.20 wt% TOC]. The samples are thermally immature, except for those located close to volcanic intrusion at Golombe that have reached the threshold for oil generation (Tmax >435 °C, production index >0.1). The petrographic analysis of sandstone revealed that they are fine-grained to coarse-grained, poorly to moderately sorted, texturally and compositionally immature to submature, subarkosic to arkosic arenites. The main diagenetic processes that affected sandstones are as follows: moderate to intense compaction characterized by the development of long, concavo-convex, and sutured contacts between grains; cementation through calcite, iron oxide, and quartz cements; alteration of mica and feldspar grains; partial to complete dissolution of feldspar, mica, amphibole grains, and calcite cement; and the replacement of feldspar and mica grains by clay minerals. Alteration and dissolution increase the porosity of sandstone through the creation of secondary pores. However, mechanical compaction through the development of a pseudomatrix and cementation as pore-filling materials have significantly reduced the quality of sandstone beds as conventional petroleum reservoirs. Hence, the best reservoir-quality sandstones in the basin are generally located in the upper portion of the basin in terms of its lithostratigraphic model. They are the cleanest sandstones with the smallest amount of cement and the lowest ductile grain content (pseudomatrix), with a thickness that varies from 3 m to 120 m and a lateral extension of 20 km. The lithostratigraphic model of the basin is characterized by an extensive lacustrine environment that provided a thick sequence of organic-rich formations; sand deposited as extensive reservoirs sandwiched between shale/claystone beds; the development of stratigraphic traps through lateral facies change; and the widespread deposition of lacustrine and floodplain claystone that provide regional seals. The similarities between the Babouri-Figuil Basin and proven petroleum systems in other WCARS rift basins suggest that the basin may host at least one petroleum system where actively generating source rocks are present.

Необходимость и область применения нержавеющих анкеров

Corrosion wear of the rock bolt elements with loss of their bearing capacity is sometimes observed in operation of the rock bolt support. Studies carried out in the mine workings secured with resin grouted rebar bolts allowed us to determine the patterns of corrosion wear of the rock bolt elements and measures to prevent it. Development of the rock bolt element corrosion is observed when they are moistened. The probability of free water content in the roof rocks increases with the growth of rock fracturing. The rate of the corrosion process increases with a decrease in the hydrogen index of water. Analysis of possible ways to prevent rock bolt support failures caused by the corrosion wear revealed that the most economical of them is the application of anti-corrosion coatings on the rock bolt support elements. Technical requirements were developed for the means of anti-corrosion protection of the metal rock bolt supports, they were selected among the anti-corrosion means available in the market of the Russian Federation, and their mine tests were carried out as the anti-corrosion coatings of the rock bolts in the most aggressive mine environment. According to the results of the mine tests, one anti-corrosion medium was identified that successfully passed the tests. The anti-corrosion coating created with this medium did not fail, corrosion failure of the rock bolt support elements was not observed. According to the test results, it was concluded that the anti-corrosion coating can prevent the failure of the rock bolt support operation. The field of application for stainless rock bolts is mine workings with long service life of the rock bolt support when the roof rocks are saturated water which pH &lt; 7. The economic effect of using the rock bolts with anti-corrosion coating would amount to 6.6 million rubles/km. On average, only 4.2% of the rock bolts supplied to mines should have an anti-corrosion coating. It is possible to predict the need for the use of stainless rock bolts before driving the mine working, which will allow determining the necessary volume of their purchase in advance.

Retrospective study of acid-base disturbances in patients with chronic kidney disease

Background. Impaired kidney function has a negative effect on the body’s acid-base status (ABS). However, a violation of ABS can worsen the course of chronic kidney disease (CKD). Therefore, during the examination and treatment of patients with CKD, it is necessary to take into account the ABS. The purpose of the study: to conduct a retrospective analysis of the dynamics of ABS indicators in patients with stage 1–5 CKD who sought outpatient medical care in a medical institution in Kyiv. Materials and methods. A retrospective, randomized, cohort study was performed of 53 medical records of patients (form 025/o) who sought outpatient medical care at the Professor Dmytro Ivanov Nephrological Clinic LLC with a diagnosis of stage 1–5 CKD from February 2022 to February 2023. Participants were examined for ABS indicators three times. They were divided into 2 groups: group 1 (n = 31) — stage 1–3 CKD and group 2 (n = 22) — stage 4–5 CKD. An analysis of ABS indicators was carried out in dyna­mics. Results. Results of multiple linear regression for patients with stage 1–5 CKD (n = 53) showed that there was a strong significant effect between potassium (K+) and glomerular filtration rate (GFR) (F(1, 13) = 10.59, p = 0.006, R2 = 0.45, R2 adj = 0.41). The results of multiple linear regression of indicators in patients with stage 1–3 CKD (group 1) demonstrated a weak insignificant influence between lactate and GFR (F(1, 15) = 1.11, p = 0.310, R2 = 0.07, R2 adj = 0.01). The results of multiple linear regression of indicators in patients with stage 4–5 CKD (group 2) showed that there is a very strong combined insignificant influence between the hydrogen index, partial pressure of carbon dioxide, partial pressure of oxygen, bicarbonate concentration, base excess of extracellular fluid, K+, total carbon dioxide, anion gap with K concentration included in the equation, base excess, lactate and GFR (F(10, –3) = 0.3, p = 58.099, R2 = –65.23, R2 adj = 155.53). Conclusions. When studying ABS in patients with stage 1–5 CKD, a correlation was found between K+ and GFR using the multiple linear regression tool. In the first group, the relationship between lactate and GFR, in the second one, all predictors had a relationship with GFR.

Magmatically driven hydrocarbon generation and fluid flow in the Namibe Basin of Angola

Abstract Magmatic activity can severely alter the thermal structure of a sedimentary basin, with variable effects on the petroleum system. The Namibe Basin of Angola (Cretaceous South Atlantic rift) contains well-exposed magmatic and petroleum system elements and allows integrated assessment of how magmatic activity can modify the petroleum system. The basin was affected by syn-rift and post-rift magmatic events, and bitumen is observed within both the Pre- and Post-Salt stratigraphical sections. In the Pre-Salt, fluorescent bitumen has a lacustrine signature and is associated with calcite and quartz cements. Onshore Pre-Salt units are thermally immature, and therefore the source rock that generated the Pre-Salt bitumen is likely located offshore. Hydrocarbons migrated or re-migrated via magmatically driven fluids, reaching the present-day onshore. Closer to magmatic units, non-fluorescent pyrobitumen was instead observed, evidencing hydrocarbon cracking processes following emplacement. In the Post-Salt, bitumen is in situ and shows marine-like signatures compatible with an immediate Post-Salt source rock depositional environment. In the immediate Post-Salt, units with very high total organic carbon values (TOC; up to 13.8%) and excellent source rock properties (hydrogen index &gt;600 mgHC g −1 TOC) have reached thermal maturation. Within the Namibe Basin these Post-Salt source units lie in proximity to major Turonian–Coniacian–Santonian volcanic centres and associated shallow intrusions, which are likely to have caused thermally forced maturation processes and generation of the Post-Salt hydrocarbons. This paper demonstrates the importance of an integrated field, petrographic and geochemical approach in unravelling the influence of magmatic activity on basin thermal structure and petroleum systems.

Northern Svalbard Composite Tectono-Sedimentary Element

Abstract The Northern Svalbard Composite Tectono-Sedimentary Element (CTSE) comprises Proterozoic, Early Paleozoic and Devonian sedimentary rocks preserved in northern Svalbard and on the adjacent shelf margin between complexes of metamorphic and crystalline basement rocks. The Northern Svalbard CTSE covers four main tectono-sedimentary elements: Tonian synrift, Neoproterozoic–Cambrian post-rift, Ordovician passive margin and late Silurian?/Devonian synextensional basins. The oldest documented sedimentary strata are greywacke and shale deposited after the Greenvillian Orogeny and assumed to be younger than 980–960 Ma. The present CTSE further includes Cambrian–Ordovician sedimentary rocks in Ny-Friesland and Nordaustlandet, while the dominant part of the CTSE are continental Old Red Sandstone sediments of the late Silurian?/Early Devonian Red Bay and Siktefjellet groups and the Early–Late Devonian Andreé Land Group onshore northern Spitsbergen. Locally, the Cambrian–Ordovician formations contain petroleum source rocks with moderate total organic carbon contents and relatively high hydrogen index values, suggesting a good potential for oil generation. There are possible reservoirs, seals and traps in some of the basins but the CTSE generally holds a very limited potential as a petroleum province, particularly as the region is under strict environmental protection.

Outcrops as windows to petroleum systems: Insights from the southern Bida Basin, Nigeria

The study assessed petroleum systems in the southern Bida Basin, Nigeria, focusing on the Cretaceous sediments. Reservoirs comprise Lokoja and Patti Formation sandstones, while shales, claystone, and siltstone serve as source rocks and stratigraphic traps/seals. Detailed studies delineating the key elements of the petroleum systems in the basin have not been conducted due to a lack of subsurface data. The goal of the current study was to use field observations, Scanning Electron Microscopy (SEM), X-ray diffraction (XRD), and geochemical and geomechanical data to evaluate key components of petroleum systems in the southern Bida Basin. The results presented in this investigation are intended to attain specific objectives, especially those lacking in the basin's study sections. Petrophysical analysis revealed that the Lokoja Sandstone has porosity of 37%–39.5% and moderate permeability of 23.22–42.29 mD. The Patti Formation sandstone reservoirs exhibited high porosity (38%–42%) and moderate to good permeability (31.54–66.48 mD), suggesting good potential reservoirs. SEM results revealed intragranular pores and micro-fractures in the Patti Shale, whereas the sandstone reservoirs in the Lokoja and Patti formations displayed fractures, facilitating hydrocarbon migration. Quartz was the dominant mineral in the sandstone units of both formations. XRD analysis revealed that brittle and clay minerals influenced the microstructure of Patti Shale. Geochemical analysis indicated promising petroleum potential in the Patti Shale, with a total organic carbon (TOC) content of 1.87 wt%, free hydrocarbon from kerogen (S1) of 0.41 mg/g, hydrogen index (HI) of 0.75 mg HC/g TOC, and production index (PI) of 0.17. The Patti and Lokoja formations' shale, claystone, and siltstone exhibited sealing potential, with a plasticity index of 24–35 and coefficient permeability of 2.8 × 10−4- 3.6 × 10−4 cm/s. Field studies, XRD, geochemical data, and geomechanical index values have confirmed the key components of the petroleum system, which in turn facilitate hydrocarbon generation, migration, accumulation, and entrapment in the basin.