Search Results (13)

Improving the isotropic magnetic properties of FeSi electrical steels has traditionally focused on enhancing their crystallographic texture and microstructural morphology. Strengthening the cube texture within a ferritic matrix of optimal grain size is known to reduce core losses and increase magnetic induction. However, conventional cold rolling followed by annealing remains insufficient to optimise the magnetic performance of thin FeSi strips fully. This study explores an alternative approach based on grain boundary migration driven by temperature gradients combined with deformation gradients, either across the sheet thickness or between neighbouring grains, in thin, weakly deformed non-oriented (NO) electrical steel sheets. The concept relies on deformation-induced grain growth supported by rapid heat transport to promote the preferential formation of coarse grains with favourable orientations. Experimental material consisted of vacuum-degassed FeSi steel with low silicon content. Controlled deformation was introduced by temper rolling at room temperature with 2–40% thickness reductions, followed by rapid recrystallisation annealing at 950 °C. Microstructure, texture, and residual strain distributions were analysed using inverse pole figure (IPF) maps, kernel average misorientation (KAM) maps, and orientation distribution function (ODF) sections derived from electron backscattered diffraction (EBSD) data. This combined thermomechanical treatment produced coarse-grained microstructures with an enhanced cube texture component, reducing coercivity from 162 A/m to 65 A/m. These results demonstrate that temper rolling combined with dynamic annealing can surpass the limitations of conventional processing routes for NO FeSi steels. Full article

The photoacoustic (PA) method is commonly used in the measurement of trace gas concentration owing to its high accuracy and reliability. However, the conventional PA method is usually used in the gas-phase environment, which leads to a long measurement time and a large equipment volume for the degassing process. In this paper, we report a scheme to measure the acetylene (C₂H₂) concentration from the acetylene–dielectric oil (C₂H₂–Oil) mixed solution without the degassing process. The frequency and intensity distribution of the PA signal in the C₂H₂–Oil mixed liquid is investigated using the finite element method (FEM). Simulation results reveal that the incident light modulation frequency and the geometry size of the PA cell are two core factors to determine the PA signal. Furthermore, a PA sensor system is constructed to measure the concentration of C₂H₂ from the C₂H₂–Oil mixed solution. The measurement results demonstrate that the intensity of the PA signal in the C₂H₂–Oil mixed solution rises mostly linearly with the concentration of C₂H₂ from 0 to 100 mL/L. The Allan variance results from the continuous tests indicate that the measurement limit of the PA sensor system is about 0.2 mL/L. This work points to a novel method for the measurement of the C₂H₂ concentration from the C₂H₂–Oil mixed solution. Full article

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. Full article

The Lunnan oilfield, nestled within the Tarim Basin, represents a prototypical extra-low-permeability sandstone reservoir, distinguished by high-quality crude oil characterised by a low viscosity, density, and gel content. The effective exploitation of such reservoirs hinges on the implementation of carbon dioxide (CO₂) flooding techniques. This study, focusing on the sandstone reservoirs of Lunnan, delves into the mechanisms of CO₂-assisted oil displacement under diverse operational parameters: injection pressures, CO₂ concentration levels, and variations in crude oil properties. It integrates analyses on the high-pressure, high-temperature behaviour of CO₂, the dynamics of CO₂ injection and expansion, prolonged core flood characteristics, and the governing principles of minimum miscible pressure transitions. The findings reveal a nuanced interplay between variables: CO₂’s density and viscosity initially surge with escalating injection pressures before stabilising, whereas they experience a gradual decline with increasing temperature. Enhanced CO₂ injection correlates with a heightened expansion coefficient, yet the density increment of degassed crude oil remains marginal. Notably, CO₂ viscosity undergoes a substantial reduction under stratigraphic pressures. The sequential application of water alternating gas (WAG) followed by continuous CO₂ flooding attains oil recovery efficiency surpassing 90%, emphasising the superiority of uninterrupted CO₂ injection over processes lacking profiling. The presence of non-miscible hydrocarbon gases in segmented plug drives impedes the oil displacement efficiency, underscoring the importance of CO₂ purity in the displacement medium. Furthermore, a marked trend emerges in crude oil recovery rates as the replacement pressure escalates, exhibiting an initial rapid enhancement succeeded by a gradual rise. Collectively, these insights offer a robust theoretical foundation endorsing the deployment of CO₂ flooding strategies for enhancing oil recovery from sandstone reservoirs, thereby contributing valuable data to the advancement of enhanced oil recovery (EOR) technologies in challenging, low-permeability environments. Full article

The micro distribution of residual oil in low-permeability sandstone reservoirs is closely related to pore structure, and the differences in pore structure often determine the reservoir’s productivity and development effectiveness from a macro perspective. On the basis of in-depth research, this paper analyzes the distribution law of the remaining microscopic oil, establishes the digital core multi-stage pore network modeling of the strongly sorted heterogeneous conglomerate reservoir in the Lower Wuerhe Formation of Block 8 of the Karamay Oilfield, the three-phase seepage simulation method considering the release of dissolved gas, and the three-phase permeability curve test. The research results are as follows: (1) Conventional physical property analysis shows that the permeability of core samples exhibits an inverse rhythmic distribution with layer depth. (2) CT core analysis and mercury injection experiments indicate that the area with porosity ranging from 9% to 21% accounts for 79% and is the main seepage channel area. Larger pores play an important role in seepage. (3) Through comparative experiments on cores with different permeability, it was found that the degassing phenomenon of low-permeability rock samples is more severe. In the actual process of reservoir development, it is necessary to reasonably handle the impact of water injection on development effectiveness, select appropriate water injection methods and cycles, and avoid premature water breakthrough in ultra low-permeability reservoirs. Full article

The use of pH-responsive polymeric micelles is a promising approach to afford the targeted, pH-mediated delivery of hydrophobic drugs within the low-pH tumour milieu and intracellular organelles of cancer cells. However, even for a common pH-responsive polymeric micelle system—e.g., those utilising poly(ethylene glycol)-b-poly(2-vinylpyridine) (PEG-b-PVP) diblock copolymers—there is a lack of available data describing the compatibility of hydrophobic drugs, as well as the relationships between copolymer microstructure and drug compatibility. Furthermore, synthesis of the constituent pH-responsive copolymers generally requires complex temperature control or degassing procedures that limit their accessibility. Herein we report the facile synthesis of a series of diblock copolymers via visible-light-mediated photocontrolled reversible addition-fragmentation chain-transfer polymerisation, with a constant PEG block length (90 repeat units (RUs)) and varying PVP block lengths (46–235 RUs). All copolymers exhibited narrow dispersity values (Đ ≤ 1.23) and formed polymeric micelles with low polydispersity index (PDI) values (typically <0.20) at physiological pH (7.4), within a suitable size range for passive tumour targeting (<130 nm). The encapsulation and release of three hydrophobic drugs (cyclin-dependent kinase inhibitor (CDKI)-73, gossypol, and doxorubicin) were investigated in vitro at pH 7.4–4.5 to simulate drug release within the tumour milieu and cancer cell endosome. Marked differences in drug encapsulation and release were observed when the PVP block length was increased from 86 to 235 RUs. With a PVP block length of 235 RUs, the micelles exhibited differing encapsulation and release properties for each drug. Minimal release was observed for doxorubicin (10%, pH 4.5) and CDKI-73 exhibited moderate release (77%, pH 4.5), whereas gossypol exhibited the best combination of encapsulation efficiency (83%) and release (91% pH 4.5) overall. These data demonstrate the drug selectivity of the PVP core, where both the block molecular weight and hydrophobicity of the core (and accordingly the hydrophobicity of the drug) have a significant effect on drug encapsulation and release. These systems remain a promising means of achieving targeted, pH-responsive drug delivery—albeit for select, compatible hydrophobic drugs—which warrants their further investigation to develop and evaluate clinically relevant micelle systems. Full article

An in situ and a batch heating experiment were applied on the fine-grained sediments of the Opalinus Clay from Mont Terri (Switzerland) and the Boom Clay of Mol (Belgium), both being currently studied as potential host formations for deep nuclear waste disposal. The purpose was here to test the impact of a 100 °C temperature rise that is expected to be produced by nuclear waste in deep repositories. The experiment on the Opalinus Clay mimicked real conditions with 8-months operating heating devices stored in core drillings into the rock. The comparison of the major, trace, rare-earth elemental contents and of the whole-rock K-Ar data before and after heating shows only a few variations beyond analytical uncertainty. However, the necessary drillings for collecting control samples after the experiment added an unexpected uncertainty to the analyses due to the natural heterogeneity of the rock formation, even if very limited. To overcome this aspect, Boom Clay ground material was subjected to a batch experiment in sealed containers during several years. The drawback being here the fact that controls were limited with, however, similar reproducible results that also suggest limited elemental transfers from rock size into that of the <2 μm material, unless the whole rocks lost more elements than the fine fractions. The analyses generated by the two experiments point to identical conclusions: a visible degassing and dewatering of the minerals that did not induce a visible alteration/degradation of the host-rock safety characteristics after the short-term temperature increase. Full article

The Paleoproterozoic Lyavaraka ultrabasic complex is one of several dunite–harzburgite–orthopyroxenite bodies exposed as shallow plutonic complexes in the Serpentinite Belt, Kola Peninsula, Russia. Lyavaraka and the other complexes are anorogenic, formed in a stable within-plate environment in the interval 2.5–2.4 Ga as members of a large igneous province formed in the Sumian cycle of igneous activity. This geotectonic setting accounts for the shallow emplacement of the strongly magnesian komatiitic magma in the Fennoscandian Shield. We recognize three stages of crystallization of the Al-undepleted magma, present as dislocated blocks. Zone I is the ultrabasic core-like zone in which olivine predominates. Orthopyroxene is the major mineral in Zone II, and Zone III contains the most evolved ultrabasic rocks in which recurrent olivine coexists with Cpx + Pl. Primocrysts of hypermagnesian Opx (Mg# 91–93) nucleated in central areas of Zone II as olivine (Mg# 89.1–90.3) was forming in Zone I. In Zone III, olivine grains of a second generation (Mg# 74.5–75.8) formed after the primocrystic Cpx (Mg# up to 88.0) appeared. The recurrence of olivine is attributed to the progressive buildup in fO₂ as a result of degassing and conversion of Fe²⁺ to Fe³⁺, well documented in our earlier studies of oxide parageneses. Full article

The determination of methane content of coal seams is conducted in hard coal mines in order to assess the state of methane hazard but also to evaluate gas resources in the deposit. In the world’s mining industry, natural gas content in coal determination is usually based on direct methods. It remains the basic method in Poland as well. An important element in the determination procedure is the gas loss that occurs while collecting a sample for testing in underground conditions. In the method developed by the authors, which is a Polish standard, based on taking a sample in the form of drill cuttings, this loss was established at a level of 12%. Among researchers dealing with the methane content of coal, there are doubts related to the procedures adopted for coal sampling and the time which passes from taking a sample to enclosing it in a sealed container. Therefore, the studies were designed to evaluate the degree of degassing of the sample taken in the form of drill cuttings according to the standard procedure and in the form of the drill core from a coal mine roadway. The results show that the determinations made for the core coincide with the determinations made for the drill cutting samples, with the loss of gas taken into account. Full article

Molecular and carbon isotopic variation during degassing process have been observed in marine shale reservoirs, however, this behavior remains largely unexplored in terrestrial shale reservoirs. Here, we investigate the rock parameters of five terrestrial shale core samples from the Xiahuayuan Formation and the geochemical parameters of thirty natural gas samples collected during field canister degassing experiments. Based on these new data, the gas composition and carbon isotope variation during canister degassing are discussed and, further, the relationship between petrophysics and the carbon isotope variation is explored. The results show that methane content first increases and then decreases, the concentrations of carbon dioxide (CO₂) and nitrogen gas (N₂) peak in the early degassing stage, while heavier hydrocarbons gradually increase over time. Shale gas generated from humic source rocks contains more non-hydrocarbon and less heavy hydrocarbon components than that generated from sapropelic source rocks with similar maturity. Time-series sampling presents an upward increase in δ¹³C₁ value during the degassing process with the largest variation up to 5.7‰, while the variation in δ¹³C₃ and δ¹³C₂ is insignificant compared to δ¹³C₁. Moreover, we find that there is only a small variation in δ¹³C₁ in shale samples with high permeability and relatively undeveloped micropores, which is similar to the limited δ¹³C₁ variation in conventional natural gas. For our studied samples, the degree of carbon isotope variation is positively correlated with the TOC content, micropore volume, and micropore surface, suggesting that these three factors may play a significant role in carbon isotope shifts during shale gas degassing. We further propose that the strong ¹³C₁ and C₂⁺depletion of shale gas observed during the early degassing stage may have resulted from the desorption and diffusion effect, which may lead to deviation in the identification of natural gas origin. It is therefore shale gas of the late degassing stage that would be more suitable for study to reduce analytic deviations. In most samples investigated, significant isotopic variation occurred during the degassing stage at room temperature, indicating that the adsorbed gas had already been desorbed at this stage Our results therefore suggest that more parameters may need to be considered when evaluating the lost gas of shales. Full article

Proximity to magma bodies is generally acknowledged as providing the energy source for hot hydrothermal reservoirs. Hence, it is appropriate to think of a “magma–hydrothermal system” as an entity, rather than as separate systems. Repeated coring of Kilauea Iki lava lake on Kilauea Volcano, Hawaii, has provided evidence of an impermeable, conductive layer, or magma–hydrothermal boundary (MHB), between a hydrothermal system and molten rock. Crystallization on the lower face of the MHB and cracking by cooling on the upper face drive the zone downward while maintaining constant thickness, a Stefan problem of moving thermal boundaries with a phase change. Use of the observed thermal gradient in MHB of 84 °C/m yields a heat flux of 130 W/m². Equating this with the heat flux produced by crystallization and cooling of molten lava successfully predicts the growth rate of lava lake crust of 2 m/a, which is faster than simple conduction where crust thickens at $\sqrt{t}$ and heat flux declines with $1/\sqrt{t}$ . However, a lava lake is not a magma chamber. Compared to erupted and degassed lava, magma at depth contains a significant amount of dissolved water that influences the magma’s thermal, chemical, and mechanical behaviors. Also, a lava lake is rootless; it has no source of heat and mass, whereas there are probably few shallow, active magma bodies that are isolated from deeper sources. Drilling at Krafla Caldera, Iceland, showed the existence of a near-liquidus rhyolite magma body at 2.1 km depth capped by an MHB with a heat flux of ≥16 W/m². This would predict a crystallization rate of 0.6 m/a, yet no evidence of crystallization and the development of a mush zone at the base of MHB is observed. Instead, the lower face of MHB is undergoing partial melting. The explanation would appear to lie in vigorous convection of the hot rhyolite magma, delivering both heat and H₂O but not crystals to its ceiling. This challenges existing concepts of magma chambers and has important implications for use of magma as the ultimate geothermal power source. It also illuminates the possibility of directly monitoring magma beneath active volcanoes for eruption forecasting. Full article

The Bonga complex is composed of a central carbonatite plug (with a ferrocarbonatite core) surrounded by carbonatite cone sheets and igneous breccias of carbonatitic, fenitic, phoscoritic and lamprophyric xenoliths set in a carbonatitic, lamprophyric or mingled mesostase. To reconstruct the dynamics of the complex, the pyrochlore composition and distribution have been used as a proxy of magmatic-hydrothermal evolution of the complex. An early Na-, F-rich pyrochlore is disseminated throughout the carbonatite plug and in some concentric dykes. Crystal accumulation led to enrichment of pyrochlore crystals in the plug margins, phoscoritic units producing high-grade concentric dykes. Degassing of the carbonatite magma and fenitization reduced F and Na activity, leading to the crystallization of magmatic Na-, F- poor pyrochlore but progressively enriched in LILE and HFSE. Mingling of lamprophyric and carbonatite magmas produced explosive processes and the formation of carbonatite breccia. Pyrochlore is the main Nb carrier in mingled carbonatites and phoscorites, whereas Nb is concentrated in perovskite within mingled lamprophyres. During subsolidus processes, hydrothermal fluids produced dolomitization, ankeritization and silicification. At least three pyrochlore generations are associated with late processes, progressively enriched in HFSE, LILE and REE. In the lamprophyric units, perovskite is replaced by secondary Nb-rich perovskite and Nb-rich rutile. REE-bearing carbonates and phosphates formed only in subsolidus stages, along with late quartz; they may have been deposited due to the release of the REE from magmatic carbonates during the hydrothermal processes. Full article

Shale gas content is the key parameter for shale gas potential evaluation and favorable area prediction. Therefore, it is very important to determine shale gas content accurately. Generally, we use the US Bureau of Mines (USBM) method for coal reservoirs to calculate the gas content of shale reservoirs. However, shale reservoirs are different from coal reservoirs in depth, pressure, core collection, etc. This method would inevitably cause problems. In order to make the USBM method more suitable for shale reservoirs, an improved USBM method is put forward on the basis of systematic analysis of core pressure history and temperature history during shale gas degassing. The improved USBM method modifies the calculation method of the gas loss time, and determines the temperature balance time of water heating. In addition, we give the calculation method of adsorption gas content and free gas content, especially the new method of calculating the oil dissolved gas content and water dissolved gas content that are easily neglected. We used the direct method (USBM and the improved USBM) and the indirect method (including the calculation of adsorption gas, free gas and the dissolved gas method) to calculate the shale gas content of 16 shale samples of the Triassic Yanchang Formation in the Southeastern Ordos Basin, China. The results of the improved USBM method show that the total shale gas content is high, with an average of 3.97 m³/t, and the lost shale gas content is the largest proportion with an average of 62%. The total shale gas content calculated by the improved USBM method is greater than that of the USBM method. The results of the indirect method show that the total shale gas content is large, with an average of 4.11 m³/t, and the adsorption shale gas content is the largest proportion with an average of 71%. The oil dissolved shale gas content which should be paid attention to accounts for about 7.8%. The discrepancy between the direct method and indirect method is reduced by using the improved USBM method, and the improved USBM method could be more practical and accurate than the USBM method. Full article