Petroleum Chemistry最新文献

The rheological performance of water-based composite salt drilling fluids under high-temperature and high-pressure (HTHP) conditions has been investigated. Using the composite salt drilling fluids from LH1 wells as the research object, its rheological parameters has been measured using a Chandler 7600 HTHP rheometer. The study compared the applicability of conventional rheological model for specific temperature and pressure conditions and explored the factor modification method for constructing HTHP rheological relations. The obtained results show that the temperature has a greater influence on the HTHP rheological properties of composite salt drilling fluid than the pressure. A conventional model fitting show that the three-parameter model outperforms the two-parameter one with the best result provided by the Herschel‒Bulkley (Herba) model, while the power-law model demonstrated the poorest result. This confirms the Herba model represents a HTHP kinetic rheological model for composite salt drilling fluids. By applying Arrhenius approximation, temperature factor corrections of the viscosity and the rheological model have been introduced to construct the coefficient functions of n, K, and T and establish the HTHP rheological kinetic equation. The revealed deviation anomalies are concentrated mainly at low shear rates (<100 s^–1) and high temperatures (>100°C), with residuals ranging from −4.464 to 0.581 and the average deviation of 3.16%. The studied analytical model demonstrates high predictive accuracy, which meets the field application requirements, and can be used for the rheological regulation of composite salt drilling fluids used for deep wells. This study provides a critical data support for optimizing the rheological properties of such fluids used in deep wells.

The conditions of the formation of stable water–petroleum emulsions stabilized by clay particles were studied. The effect of unmodified and modified montmorillonite on the emulsion stabilization was studied for model systems consisting of pure toluene and distilled water. The clay particles were modified with resin–asphaltene components of the crude oil from the Romashkino oilfield. The influence exerted by the degree of modification and concentration of clay particles on the stability of water–petroleum emulsions was revealed. The degree of modification was estimated from the IR spectra. The resin–asphaltene components modify the surface of clay particles. The degree of modification increases with an increase in the modification time and concentration of petroleum components. Stable emulsion samples were obtained with modified clay particles. The toluene phase in these emulsions is stabilized by clay microparticles, which is characteristic of Pickering emulsions.

The paper describes the structural and rheological investigation of two thermally pretreated highly paraffinic resinous crude oils, specifically the oils from the South-Maiskoye oil field (SM) and from the Archinskoye oil and gas condensate field (AR). Pretreating SM (asphaltene/resin ratio ≈ 0.09) at 40°C induced an anomalous rise in both viscosity–temperature behavior and asphalt–resin–paraffin deposit (ARPD) formation—in contrast to pretreatment of the same oil at 10, 20, and 60°C. For AR (with its asphaltene/resin ratio of about 0.23), elevating the pretreatment temperature to 60°C decreased the viscosity and pour point and increased the concentrations of resinous-asphaltenic components and solid n-alkanes in the ARPDs. Photon correlation spectroscopy revealed a spontaneous growth of aggregates when the SM oil was cooled from 35 to 25°C. Cooling the AR oil from 50 to 35°C generated large and small aggregates simultaneously.

A series of low-nickel (0.7–2.9 wt %) catalysts for dry reforming of methane (DRM) were prepared from specially synthesized hydrotalcite-derived nickel–aluminum–magnesium hydroxo salts. The texture and catalytic performance of these materials were found to depend on the Ni loading in the precursor hydroxo salts. Under DRM conditions, the 2.9 wt % Ni precursor evolved into a layered catalyst that contained non-uniformly dispersed metallic Ni nanoparticles. The catalysts developed from lower-Ni samples showed dense homogeneous textures and uniform dispersion of metallic Ni. While the 2.9 wt % Ni catalyst achieved high product yields at 900°C (94–97% CO, 92–96% H₂), it was particularly susceptible to carbon deposition. The catalysts evolved from the 0.7 and 1.8 wt % Ni precursors demonstrated lower coking levels. Moreover, while lowering the Ni loading somewhat decreased syngas yields, it enhanced the CO and H₂ productivity per gram of nickel. Even at 600°C the catalysts still exhibited appreciable productivity.

The addition of methoxyl radical СН₃О^• to ethylene with the formation of various isomers and oxygen-coordinated forms of the СН₃ОСН₂СН₂^• radical was analyzed in detail. The scheme of possible reactions involving these species was analyzed. This radical and products of its further transformations can play a certain role in the mechanism of the gas-phase oxidation of hydrocarbons. The potential energy surface of the СН₃О^• + С₂Н₄ system was analyzed within the framework of B3LYP and M06-2X hybrid methods of the density functional theory (DFT) and of CBS-QB3 ab initio composite method of quantum-chemical calculations. The minimal energy pathways of the reactions CH₂O + C₂H₅^•, CH₃OH + C₂H₃^• and of the CH₃OCH₂CH₂^• adduct formation were calculated. In particular, the reactions of intermolecular hydrogen atom transfer with the formation of CH₂O + C₂H₅^• and CH₃OH + C₂H₃^• are less favorable energetically than the consecutive addition of СН₃О^• to ethylene, isomerization, and decomposition of the adduct with the generation of ethyl radical participating in the chain propagation.

Using ¹³C NMR spectroscopy, a representative set of crude oils and gas condensates (75 samples from 51 oil fields) from the Timan–Pechora oil and gas basin (OGB) was investigated. The structural-group composition of crude oils, and specifically the total concentrations of aromatic and n-alkyl moieties, were identified for the first time over the entire basin. Distribution density plots were presented for all the composition parameters measured. It was demonstrated that, because all the parameters exhibit polymodal distribution and substantially deviate from normal, a nonparametric statistical analysis is needed for the data processing. In particular, medians and median confidence intervals, rather than means or root-mean-square deviations, should be relied upon. When compared to the crude oil composition in the previously explored OGBs, the Timan–Pechora crudes were found to be closest to the West Siberian OGB. A considerable difference in aromaticity was observed compared to the East Siberian and North Caucasus oils. An equally large difference between the Timan–Pechora and North Caucasus oils was found for the n-alkyl composition characteristics. The average length of n-alkyl moieties in the Timan–Pechora OGB markedly exceeds that in the East Siberian crudes. When compared to the Volga–Urals basin, the Timan–Pechora oils exhibit a relatively small (although statistically significant) difference in aromaticity and a similar content of n-alkyl moieties. As was the case in an ¹H NMR investigation of the same oils that was carried out previously, the Timan–Pechora OGB was classified into four major tectonic groups: the Varandei–Adzva zone, Khoreivei depression, and Kos’yu-Rogovskaya depression; the Izhma–Pechora syneclise and Upper Pechora depression; the Pechora–Kozhva aulacogen; and the East Timan megaswell. Furthermore, the crude oils from Triassic and Permian reservoirs were considered separately from those from Devonian reservoirs. For the majority of composition parameters, only small (although statistically significant) differences were found between most crude oil groups: significance levels in the range of 0.01–0.05 prevailed over those between 0.001 and 0.01. Among Devonian deposits, crude oils from the Pechora–Kozhva aulacogen stand out for their lower aromaticity.

Hydrogen gas production is considered a highly promising technique in the field of sustainable and eco-friendly energy sources. The process of using a membrane to electrolyze brine is a vital approach for the creation of H₂ gas, Cl₂ gas, and NaOH. The corrosion resistance of the cathode electrode material and the contaminants present in the brine are the key determinants that impact this process. This study utilized cathode electrodes made from a variety of materials, including AlSI 304 and AlSI 316L stainless steel, with graphite as an anode electrode. Iraq’s Al-Basra salt resources, specifically the Al-Fao saltern, provided the brine for this study. The electrodes were subjected to different voltages of 4, 6, and 12 volts for duration of three hours. The salt impurities underwent NaOH treatment at a temperature of 80°C in order to induce precipitation as solid hydroxides, which were then filtered by an air vacuum device. The results indicated that the 304 stainless steel electrodes exhibit stability under low voltages but have diminished hydrogen emission via the cathode electrode. However, at higher voltages, the AlSI 304 electrode experiences significant pitting corrosion. This study clearly showed that when operating at voltages of 6 and 12 V, the AlSI 316L cathode electrode is best suited as the electrode material, which does not suffer from pitting corrosion. Graphite is the optimal material for an anode electrode. Through the research, a membrane system was created using locally available and inexpensive components. This system proved to be effective in producing the previous materials, especially sodium hydroxide, with a purity level of 40.50%. Additionally, the salt purification procedure successfully produced high recovery rates of 68.77% for magnesium hydroxide and 49.89% for calcium hydroxide, enabling their utilization in various industrial sectors.

The Tendrara–Missour Basin in eastern Morocco hosts the country's largest gas field, featuring a proven petroleum system with Paleozoic source rocks and a Triassic siliciclastic reservoir sealed by Late Triassic and Early Jurassic salt formations. This study evaluated the hydrocarbon generative potential and thermal maturity of Carboniferous source rocks via geochemical analysis of 215 samples from four wells (OSD-1, TE-1, TE-2, and TE-3). The results indicate that the majority of the samples were characterized by a poor to fair content of organic matter, with the total organic carbon (TOC) values less than 1%. These samples were composed mainly of type III (gas prone) and type IV (non-generative) kerogen, with the hydrogen index (HI) < 150 mg HC/g TOC. However, certain intervals, particularly in the OSD-1 well, displayed excellent source rock characteristics with the TOC values exceeding 4% and a mixture of the type II/III kerogen with the HI values exceeding 150 mg HC/g TOC. The maturity levels across the well ranged from immature to post-mature, with vitrinite values varied within 0.58–2.56%. The burial history modeling in the OSD-1 and TE-3 wells indicated that the hydrocarbon generation from the Carboniferous source rocks started during the Late Carboniferous–Permian period, i.e., during the Hercynian orogeny. Volumetric calculations based on the Monte Carlo simulation estimated the generative potential of the Carboniferous source rocks to be approximately 200 000 tons/km² (P50). The accumulated volumes derived from the Carboniferous source rocks (P50) are estimated at approximately 300 million barrels of oil and 2.5 trillion cubic feet (TCF) of gas.

Two types of Fe-silicalite-1 catalysts were synthesized: microcrystals (4–6 μm, via hydrothermal treatment) and nanocrystals (20–50 nm, via steam-assisted crystallization). It was demonstrated that oxytetracycline adsorbed on the external crystal surface, and the experimental Langmuir approximation agreed with the theoretical data based on crystal geometry. Although both catalysts exhibited equal activities in H₂O₂ decomposition, the nanocrystalline Fe-silicalite-1 achieved a higher degree of mineralization due to its different textural properties. Moreover, the nanocrystalline sample provided an H₂O₂ utilization efficiency approximately 90% higher than that of the microcrystalline sample.