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Plasma‐assisted low‐pressure cold spraying and conventional cold spraying methods are used to prepare copper coatings on copper substrates. The thickness, porosity micromorphology, and mechanical and corrosion properties of the copper coating prepared by high‐pressure cold spraying and plasma‐assisted low‐pressure cold spraying are studied. The results indicated that in single‐pass deposition, the copper coating prepared by plasma‐assisted low‐pressure cold spraying has a small porosity and a thick coating under the spraying conditions with the same powder feeding rate, which has a better deposition effect. The coating grains prepared by the plasma‐assisted method undergo a recrystallization process, and the grains are refined. Plasma‐assisted low‐pressure cold spray technology can achieve a good repair effect on parts. [ABSTRACT FROM AUTHOR]

In-situ carbon dioxide mineralization in basalt rocks has been identified as a scalable, fast, safe, permanent, and cost-effective method to offset the anthropogenic carbon dioxide emissions. In-situ carbon dioxide mineralization refers to underground carbon dioxide transformation to carbonate minerals in basalt reservoirs. Although current field applications achieved fast in-situ carbon dioxide mineralization, limited petrophysical criteria have been proposed to screen a potential site to implement in-situ carbon dioxide mineralization. To fill this knowledge gap, geochemical modellings were performed to find an optimal petrophysical recipe, including pressure, temperature, pH, and mineral composition, to conduct in-situ carbon dioxide mineralization. The geochemical modellings showed that increasing pressure was favourable to increase water uptake of carbon dioxide, host rock dissolution, and in-situ carbon dioxide mineralization. However, a higher temperature depressed the in-situ carbon dioxide mineralization. Furthermore, the in-situ carbon dioxide mineralization was unravelled to be heavily pH dependent. Most magnesite precipitated in pH range from 9 to 11. Moreover, the forsterite was identified as the major contributing minerals while anorthite, fayalite, and diopside played a minor role in the in-situ carbon dioxide mineralization. This investigation provided a general protocol to screen the optimal petrophysical conditions for in-situ carbon dioxide mineralization. [ABSTRACT FROM AUTHOR]

Accurate estimation of hydrocarbon saturation is significant for log interpreters to evaluate tight sandstone formations. It is difficult to use conventional wireline logs to calculate hydrocarbon saturation in complex reservoirs. Dielectric dispersion logs are processed using dielectric models to obtain accurate saturation assessment, especially in high salinity shaly sand formations. However, the dielectric models consist of complex refractive index method model and shaly sand model ignore the impact of clay effects on complex refractive index method model, and the dielectric dispersion logs generated by them appear several unphysical phenomena in the clay‐bearing formations, such as the permittivity data at the highest frequency are greater than those at the second highest frequency and the conductivity data at the highest frequency are lower than those at the second highest frequency. This paper modifies the dielectric models by introducing a combined conductive phase in complex refractive index method model to correct the unphysical behaviours. Revised models are combined with four permittivity and four conductivity logs acquired by dielectric scanner at 24, 102, 360 and 960 MHz to inverse the water saturation, water salinity, textural index for water‐bearing pore and fraction of clay‐related phase. The complex refractive index method model interprets the logs measured at 960 MHz and shaly‐sand model interprets other dielectric dispersion logs. The particle swarm optimization algorithm is used to search inversion parameters. The results of forward simulation show that the revised models can correct unphysical behaviours of dielectric dispersion logs generated by the original models. Moreover, we apply original models and revised models to laboratory core data. The results of experiments show that the mean relative error values of the original models are 19.38% and 23.60% and of the revised models are 5.54% and 6.28% in two cases. It shows that the revised models are more accurate than the original models to interpret dielectric dispersion logs of tight sandstone reservoirs. [ABSTRACT FROM AUTHOR]

To explore the structural effects on transport properties in carbon gels, an improved method has been introduced to regenerate their nanostructure and numerically illustrate the adjustability of their porous characteristics with the variation of synthesis parameters. Two lattice Boltzmann equations are applied to investigate the permeation and diffusion in the gel structures at the pore scale, and the apparent permeability is formulated to describe the total mass flux using the dusty gas model. The structural properties of the reconstructed models and calculated apparent permeabilities have been fully validated by various experiments. A decoupled analysis of the impact of structural parameters on transport properties demonstrates that increasing porosity and pore size, while decreasing geometric tortuosity, leads to more pronounced changes in intrinsic permeability compared to gas diffusivity. By utilizing a database that encompasses 240 reconstructed gels, a structural–functional relationship for transport properties in carbon gels could be proposed. Concerning the intrinsic permeability, a near quadratic relationship with the porosity and mean pore size, independent of particle size, could be concluded. For the nondimensional effective diffusivity, a power exponent of 1.85 associated with porosity is proposed, and its independence of pore size could be revealed. In addition, for gels with porosities under 0.65 and mean pore sizes less than 133 nm, diffusion supersedes permeation as the dominant term in total mass transfer, indicating that particle sizes have a more pronounced influence on the apparent permeability. The predictive model offers guidance for tailoring the transfer properties of carbon gels at the stage of preparation. [ABSTRACT FROM AUTHOR]

The Late Albian- Early Turonian Formation is the second-largest carbonate reservoir in the South and Southwest of Iran hosting significant accumulations of hydrocarbons deposited on the edge of the Neotethys. The purpose of this study is to analyze the sequence stratigraphy and Milankovitch cycles of the Sarvak Formation in three wells of the Anaran exploration block by using the Maximum Entropy Spectral Analysis (MESA) of gamma ray logs and integration with core studies to achieve a comprehensive understanding of the formation. The study of 353 microscopic samples led to the identification of 8 microfacies including (a) mudstone to oligostigenid wackestone with benthic and pelagic foraminifera, (b) packstone-rudstone, (c) rudistic with benthic foraminifers, (d) bioclast intraclast, (e) grainstone with benthic foraminifers, (f) peloid Wackestone to peloid wackestone with low benthic foraminifera diversity, (g) Peloid packstone with diverse benthic Foraminifers and (h) Bioclast Wackestone, which are distributed in three facies belts ranging from lagoon to shoal and open marine settings. In addition to four third-order sedimentary sequences were also identified based on facies changes combined with the Prediction Error Filter Analysis (PEFA), Integrated Prediction Error Filter Analysis (INPEFA) diagrams. Examining the Milankovitch cycles based on the analysis of the distances between gamma peaks and MESA revealed 100 thousand year cycles. Orbital dating according to the counting of the Milankovitch cycles indicates the equivalent age of 11 to 12 million years for the Sarvak Formation. [ABSTRACT FROM AUTHOR]

In this study, we integrated cores and wireline logs to evaluate the petrographical and petrophysical properties of the Late Miocene Abu Madi sandstone reservoir from the onshore WAK gas field. Thin section petrographic analyses indicate that the reservoir consists of coarse to fine-grained, poorly sorted, subangular to subrounded glauconitic quartz arenites exhibiting high mineralogical maturity, poor textural maturity, and good volume of intergranular porosity. Based on the downhole pressure data, we estimated that the gas gradient was somewhere between 0.24 and 0.26 psi/m. The SEM images suggest the pore filling authigenic chlorite and kaolinite cementation to be the dominant diagenetic process reducing the reservoir quality. The presence of concavo-convex grain contacts in the reservoir samples is indicative of a moderate degree of mechanical compaction by burial load. The massive sandstone reservoir facies represents stacked braided fluvial channels deposited during a lowstand system tract unconformably above the Qawasim Formation. Based on well log-based petrophysical analyses, the Abu Madi reservoir has a total porosity of 17–20 % with 14.6–18.3 % effective porosity and 39.4 to 47.9 % water saturation. Gross reservoir thickness varies between 28.3 and 51.1 m, whilst the net pay thickness ranges between 18.4 and 43.7 m, which translates to a high net-to-gross (N/G) ratio of 0.65–0.84. Lateral distribution of the petrophysical parameters infers a superior reservoir quality towards the central part of the studied field which should be targeted for future infill development well drilling. The reservoir heterogeneity was mapped to substantially decrease the uncertainty of future drilling. [ABSTRACT FROM AUTHOR]

The sandstone of Abu Madi clastic reservoir constitutes the prime gas-producing reservoir in the Nile Delta region. So, the present research aims to delineate its microfacies and dominant diagenetic features and their effect on the petrophysical characteristics of the Abu Madi reservoir in the Faraskur Gas Field. This could be achieved by integrating the petrographical studies and the conventional data to divide the reservoir into some reservoir rock types (RRTs) to delineate the impact of the mineral composition and diagenetic features on their reservoir quality and hydraulic flow zones. Petrographically, most samples are immature and described as angular to subrounded, poorly sorted, and slightly cemented. Five clastic microfacies types are recorded in the Abu Madi Formation: (1) quartz arenite, (2) feldspathic quartz arenite, (3) sub-feldspathic quartz arenite, (4) quartz wacke, and (5) sub-feldspathic quartz wacke. The most important post-depositional processes affecting the reservoir quality are the precipitation of pyrite and microsparite, as well as the feldspars alteration into authigenic dispersed clays represented by kaolinite and smectite/illite mixed layers. The dominant pore types are the primary intergranular, with some subsidiary fractures and dissolution pores. To check the reservoir quality of the Abu Madi clastics, the NPI (normalized porosity index), FZI (flow zone indicator), RQI (reservoir quality index), and λk (permeability anisotropy) were estimated. Petrophysically, the studied samples are summed up into four RRTs, with the RRT4 group has the lowest ∅ and k values (av. ∅ = 16.2%, av. kH = 6.87 md) and the lowest reservoir quality parameters (av. FZI = 0.89 μm, av. DRT = 10.4, av. RQI = 0.18 μm, av. R35 = 1.26 μm). On the contrary, the RRT1 group has the best petrophysical and reservoir parameters (av. ∅ = 25.9%, av. kH = 2695 md, av. DRT = 14.9, av. RQI = 3.12 μm, av. FZI = 8.85 μm, av. R35 = 32.7 μm). The permeability anisotropy of the RRT2 and RRT3 is the highest in Faraskur Field (av. λk = 2.4 and 2.62, respectively). This study is applicable to other extensions of the Abu Madi reservoirs in the Nile Delta basin to help in predicting their reservoir quality, petrophysical properties, and their hydrocarbon potentiality. [ABSTRACT FROM AUTHOR]

During drilling operations, naturally, fractured formations are prone to show serious mud losses, which hinder drilling and increase nonproductive time and costs. The influencing factors of dynamic fluid loss are important for optimizing drilling parameters, reducing drilling fluid loss, and protecting oil and gas reservoirs. In this study, we simulated the dynamic filtration loss of drilling fluid during drilling under formation conditions using commercial software CMG (Computer Modelling Group). The effects of filtration time, filtrate viscosity, pressure difference, internal filter cake permeability, and external filter cake permeability on filtration loss were investigated. The simulation results showed that the permeability of the external mud cake is an important factor to control the fluid loss, and the pressure consumed by the external mud cake with low permeability can account for more than 90% of the total pressure difference. When the permeability of the external mud cake is high, the permeability of the internal mud cake also has a significant influence on the dynamic fluid loss. Under formation conditions, the dynamic fluid loss of radial fluid loss is still proportional to the filtration time and pressure difference, and inversely proportional to the filtrate viscosity of drilling fluid. Under the simulated conditions, the pressure will quickly transfer to the boundary, and the formation pressure at the same position in the formation will gradually increase, while the increase is relatively small with a constant filtration rate. The results of this paper can be used to the real site for drilling optimization. This numerical analysis method can be easily applied to filtrate loss analysis, formation damage area calculation, and other radial flow-related study. [ABSTRACT FROM AUTHOR]

Dual‐energy X‐ray computed tomography consists of imaging objects using two incident X‐ray beams of different energy to distinguish the different compounds within a sample based on their density (electron density, ρe) and elemental composition (effective atomic number, Zeff). The stoichiometric calibration for dual‐energy X‐ray computed tomography was already successfully implemented to identify single and homogeneous minerals easily and non‐destructively. It is here applied for the first time to a more complex and heterogeneous sample, a varved sediment core with three distinct facies. The output of dual‐energy X‐ray computed tomography was compared against elemental geochemistry obtained at the same resolution using a micro‐XRF core scanner. The three individual facies can be successfully differentiated using dual‐energy X‐ray computed tomography because their range of ρe and Zeff values allow their discrimination. Correlations with elemental geochemistry are also discussed but are less conclusive, probably because of variations in grain size and porosity, and because these high resolution analyses were not performed at the exact same location. The paper not only eventually discusses the limitations when using dual‐energy X‐ray computed tomography on sediments but also demonstrates its potential to quantitatively study sediment cores in a non‐destructive way. [ABSTRACT FROM AUTHOR]

Tight sandstone oil reservoirs in the Upper Triassic Yanchang Formation of the Ordos Basin are the most promising exploration and development fields owing to their huge production potential. Even though they have received considerable attention in recent years, common productivity prediction methods were not well applied during pre-development owing to their strong internal heterogeneity. In this study, the factors influencing oil production of the Chang 9 Member in the Jiyuan area were investigated and summarized based on drill cores, such as sediment characteristic analysis, lithofacies analysis, other analytical tests, and conventional logging curves. The findings show that fine-sandstone reservoirs with smooth sand body architectures are the main types of tight sandstone commercial oil reservoirs. Furthermore, having high porosity and oil content are prerequisites for commercial oil reservoirs, and the cumulative thickness of effective reservoirs serves as a crucial resource base for them. Through the analysis of logging curves, the relative center of gravity, deviation root of variance, petrophysical index, effective reservoir thickness, and evaluation indicator were used to predict daily oil production, thereby establishing the identification criteria for the ranking of tight sandstone oil reservoirs using logging. Then, the productivity of each reservoir in a single well was predicted by processing the log data from each well using the proposed method, and the productivity prediction results agreed well with the tested results of the perforated interval. This approach highlights the integrated influence of geological factors, physical properties, and the thickness scale of an effective reservoir, thereby improving the predictive capacity of logging curves. Additionally, the proposed methods significantly reduce the need for reservoir parameters better than previous ones, streamline operations, and improve practical applications. [ABSTRACT FROM AUTHOR]

Due to the inherent deposition environment and extraction challenges in a coal seam, quantification of its gas transport behavior serves as the prerequisite to predict and evaluate accurately dynamic coalbed methane (CBM) recovery. In this work, a dual-porosity/single-permeability (DPSP) model is proposed for evaluating the gaseous methane flow performance by considering both the free gas density gradient and pressure gradient. More specifically, methane extraction dynamics was monitored via on-site boreholes with different spacings, and the two key gas flow parameters (i.e., diffusion coefficient and permeability coefficient) were determined and validated by minimizing the deviations between the field measurements and the simulated production profiles. Sensitivity analysis was conducted to examine the effect of both gas flow rate in a borehole and gas mass transfer flux from coal matrix to fractures on the production performance. The gas flow rate was found to be very sensitive to the permeability coefficient at the early extraction stage and then dominated mainly by the diffusion coefficient during the later extraction stage. The gas mass transfer flux from the matrix subsystem to the fracture subsystem exhibited distinct peak features due to the hysteresis of gas desorption in coal matrix. To extract methane in a coal seam, gas pressure in the matrix subsystem decreases much less than that in the fracture subsystem. Compared with the traditional single-porosity/single-permeability model, the newly proposed DPSP model allowed us to correct the overestimated CBM production and identify the underlying gas flow mechanisms. By introducing a critical extraction radius (CER) during a CBM extraction process, a theoretical equation associated with the CER, original methane content in a coal seam and methane extraction time was eventually formulated so that the CER and borehole spacing in some coal seam areas with different methane contents can be determined in a convenient and accurate manner. [ABSTRACT FROM AUTHOR]

The proportion of offshore low-permeability gas reservoirs has increased, and the differences in pore structure have affected well productivity, limiting the development of offshore low-permeability gas reservoirs on a larger scale. To characterize the complex pore-throat structure of low-permeability reservoirs, high-pressure mercury intrusion and nuclear magnetic resonance (NMR) experiments were conducted on low-permeability core samples. The double-peak Gaussian function fitting curve method was used to convert the NMR T2 spectrum into pseudo-capillary pressure curves to quantitatively characterize pore size and distribution. Furthermore, by analyzing the correlation between the NMR T2 spectrum and parameters such as large pore volume and medium-large pore porosity, a new parameter that better reflects reservoir flow capacity was constructed for pore-throat evaluation. Lastly, a prediction model for pore-throat and petrophysical parameters was established using multivariate regression based on the response relationship between logging curves and reservoir classification parameters. The results show that the pore-throat distribution of the third section of the Lingshui Formation low-permeability reservoir exhibits bimodal and unimodal patterns, with overlapping regions between small and large pore curves in both types. The overlapping region is smaller in the bimodal pattern and larger in the unimodal pattern. The pore system can be divided into large pores, medium pores, and small pores based on the distribution ranges of the fitted curves for small and large pores and the overlapping region. The medium-large pore porosity and large pore porosity effectively evaluate reservoir petrophysical properties and pore structure. The better the large-medium pore system developed, the better the petrophysical properties are, and the higher the movable fluid saturation is. A classification standard for low-permeability reservoirs was established based on comprehensive evaluation parameters primarily focusing on large pores and medium-large pores. The reservoirs were divided into three types. Type I and type II reser-voirs have better development of large-medium pores and good petrophysical properties, comprehensive evaluation parameter values are greater than 7 and 10 respectively, and relatively high movable fluid sat-uration is generally above 65.75%. Type IE reservoirs have relatively poor petrophysical properties, smaller values for comprehensive evaluation parameters of large pores and medium-large pores, complex pore-throat structure, and relatively low movable fluid saturation. These results can provide guidance for the economic and effective development of low-permeability gas fields. [ABSTRACT FROM AUTHOR]

The formation and decomposition process of natural gas hydrate (NGH) involves many disciplines and theories. Comprehensively evaluating the mechanical and physical properties of hydrate-bearing sediments (HBS) and clarifying the influence law of hydrate decomposition on reservoir structure. It is of great significance to realize the safe exploitation of NGH. At present, the test research on HBS shows the characteristics of diversification, multi-scale and multi-discipline. In order to enhance the comparison of test conclusions and promote the correlation of science and technology. In this study, based on different experimental test methods, the existing test methods are categorized into two types: direct test methods and indirect test methods. By summarizing and analyzing the triaxial test and direct shear test of hydrates, the commonalities and differences of different types of hydrates are pointed out. Meanwhile, the mechanical behavior of hydrate under different influencing factors is reviewed in particular to guide practical works. Then, by combing the visualization techniques of hydrate laboratory tests. The applications of X-ray computed tomography (X-CT) and nuclear magnetic resonance (NMR) in microstructure, pore space, and morphology observation are emphasized. Additionally, an overview of the acoustic and electrical characterization of hydrates in geophysical methods is presented. The correlation of acoustic wave detection and resistivity test with hydrate distribution morphology and saturation estimation is discussed. Finally, the problems existing in the current HBS experimental research are analyzed and targeted suggestions are given. The future development trend of HBS experimental research is discussed, with a view to providing ideas and references for HBS experimental research. • Mechanical and physical properties of HBS are analyzed. • The results of triaxial test and direct shear test on HBS are summarized. • The visualization method of HBS are introduced. • The application of geophysical methods to hydrate research is illustrated. • The current status and challenges of experimental hydrate research are outlined. [ABSTRACT FROM AUTHOR]

Underground Hydrogen Storage (UHS) in the subsurface is an alternative to overcome limitations associated with a fluctuating production of renewable energy sources. The excess energy produced can be converted to hydrogen and stored in porous media. Hydrogen is injected and produced from geological formations via wells. There are several concerns regarding the interactions of hydrogen with the different well components responsible for maintaining proper well integrity, such as cement. This experimental study investigates the interaction between molecular hydrogen and cement Class H by characterizing samples using different physical and chemical tests. Results showed samples exposed to molecular hydrogen exhibited a greater compressive strength in both the short and long terms. Porosity and permeability were found to be lower in samples exposed to molecular hydrogen. NMR distributions showed a reduction of larger pores and an increase of smaller pore spaces. Acoustic velocities showed an increase of Young's Modulus, Shear's Modulus and a slight decrease in Poisson's ratio. The compositional analysis demonstrated that hydrogen presence increases the amount of portlandite and ettringite formed. The crystalline needle-shaped structure observed in the SEM confirmed the presence of portlandite and ettringite within some of the larger pores. This experimental study showed that molecular hydrogen present could increase the formation of portlandite and ettringite, causing a shift in the porosity distribution increasing the mechanical strength of the cement. • Hydrogen does not negatively impact cement during underground hydrogen storage. • Hydrogen increases hydrated product formation in cement after 168 days. • Exposed samples show higher strength and lower porosity and permeability. • Hydrogen affects cement composition, microstructure, and pore size distribution. • Results showed molecular hydrogen improves well integrity. [ABSTRACT FROM AUTHOR]

Due to the complex nature of the pore system and the diversity of pore types, carbonate rocks pose a challenge in terms of their spatial characterization. Unlike sandstones, permeability in carbonates is often not correlated conclusively with porosity. A methodology for preliminary qualitative spatial characterization of reservoirs in carbonate rocks is presented in this article, with a focus on interparametric relationships. It endeavors to apply this methodology to a reservoir situated within the Main Dolomite formation in the Polish Lowlands. Fundamental analyses rely on data plotted within rock physics templates (RPT), specifically, cross-plots of acoustic impedance as a function of the product of compressional and shear wave velocities in well log profiles. The analysis of interparametric relationships was conducted on well log profiles and subsequently integrated with seismic data using neural network techniques. Areas with the greatest potential for hydrocarbon accumulation and areas potentially exhibiting enhanced reservoir properties were identified based on the outcomes of the well log profile analysis and parametric models. The qualitative assessment of the reservoir, rooted in interparametric dependencies encompassing lithofacies characteristics and elastic and petrophysical parameters, together with reservoir fluid saturation, forms the basis for further, more detailed reservoir analysis, potentially focusing on fracture modeling. [ABSTRACT FROM AUTHOR]

Pore fluids are ubiquitous throughout the lithosphere and are commonly invoked as the cause of induced seismicity and slow earthquakes. We perform lab experiments to address these questions for drained fault conditions and low pore pressure. We shear simulated faults at effective normal stress σn′ $\left({\sigma }_{n}^{\prime }\right)$ of 20 MPa and pore pressures Pp from 1 to 4 MPa. We document the full range of lab earthquake behaviors from slow slip to elasto‐dynamic rupture and show that slow slip can be explained by the slip rate dependence of the critical rheologic stiffness without dilatancy hardening or other fluid effects. Our fault permeabilities ranges from 10−18 to 10−17 m2 with an initial porosity of 0.1 and estimated fluid diffusion time ≈1 s. Slow slip and quasi‐dynamic fault motion may arise from high Pp at higher pressures but dilatancy strengthening is not a general requirement. Plain Language Summary: Earthquakes begin and propagate within the fluid‐saturated rocks of Earth's crust. Many investigators have suggested that high pore fluid pressure (Pp) is essential for slow earthquakes and tremor. These studies rely on the idea that changes in Pp can impact rupture propagation speed by dilatant volume increase during faulting with concurrent increases in fault effective normal stress. Thus, understanding the processes that produce slow‐slip versus dynamically propagating rupture is integral to seismic hazard forecasting. Here, we describe experiments on granular faults that produce the full spectrum of slip observed in nature. We measure the mechanical and hydraulic behavior of the faults and determine that frictional and fluid‐driven processes occur in conjunction. Importantly, we demonstrate that frictional processes are sufficient to explain slow‐slip when fluid migration is not inhibited. We demonstrate that for low pore fluid pressures, the full transition from slow slip to dynamic rupture events can be explained as a frictional effect via the critical rheologic stiffness. Key Points: The frictional stability transition does not require dilatant hardening for granular fault zones sheared at low pore pressuresSlow earthquakes and quasi‐dynamic fault slip can be explained by the strain‐rate dependence of the critical fault stiffness (Kc)For the effective normal stresses studied, pore pressure has a negligible impact on frictional stability and the mode of fault slip [ABSTRACT FROM AUTHOR]

Underground hydrogen storage in depleted hydrocarbon reservoirs and aquifers has been proposed as a potential long-term solution to storing intermittently produced renewable electricity, as the subsurface formations provide secure and large storage space. Various phenomena can lead to hydrogen loss in subsurface systems with the key cause being the trapping especially during the withdrawal cycle. Capillary trapping, in particular, is strongly related to the hysteresis phenomena observed in the capillary pressure/saturation and relative-permeability/saturation curves. This paper address two key points: (1) the sole impact of hysteresis in capillary pressure on hydrogen trapping during withdrawal cycles and (2) the dependency of optimal operational parameters (injection/withdrawal flow rate) and the reservoir characteristics, such as permeability, thickness and wettability of the porous medium, on the remaining hydrogen saturation. To study the capillary hysteresis during underground hydrogen storage, Killough [1] model was implemented in the MRST toolbox [2]. A comparative study was performed to quantify the impact of changes in capillary pressure behaviour by including and excluding the hysteresis and scanning curves. Additionally, this study investigates the impact of injection/withdrawal rates and the aquifer permeability for various capillary and Bond numbers in a homogeneous system. It was found that although the hydrogen storage efficiency is not considerably impacted by the inclusion of the capillary-pressure scanning curves, the impact of capillary pressure on the well properties (withdrawal rate and pressure) can become significant. Higher injection and withdrawal rates does not necessarily lead to a better performance in terms of productivity. The productivity enhancement depends on the competition between gravitational, capillary and viscous forces. The observed water upconing at relatively high capillary numbers resulted in low hydrogen productivity. highlighting the importance of well design and placement. [Display omitted] • Buoyancy plays a significant role on UHS performance. • A dimensionless number analysis to study the influence of injection/withdrawal schemes on UHS performance. • Capillary pressure scanning curves did not significantly affect the hydrogen saturation distribution. • Water upconing limits the UHS performance at high flow rates. • Interplay between Bond and capillary numbers should be considered for UHS. [ABSTRACT FROM AUTHOR]

In this work, single-phase (Ce 0.2 Zr 0.2 La 0.2 Sm 0.2 Nd 0.2)O 2-δ high-entropy fluorite oxides (HEFOs) were successfully prepared by conventional solid-phase reaction method and crystal structure and microstructure were studied in-depth. Single-phase (Ce 0.2 Zr 0.2 La 0.2 Sm 0.2 Nd 0.2)O 2-δ is formed at 1600 °C for 12 h, and five cationic elements are uniformly distributed without any segregation at the micrometer and nanometer scales. And the XRD patterns with Rietveld refinement reveal the formation of single-phase fluorite structure of (Ce 0.2 Zr 0.2 La 0.2 Sm 0.2 Nd 0.2)O 2-δ. The SAED patterns on the [0 1 ‾ 1] band axes are similar to the diffraction patterns of face-centered cubic fluorite structure, and the standard deviation of the cation radius (coordination VIII) distribution of the specimens is 0.1277, which is again identified as forming a single-phase fluorite structure. The bulk specimens are solid compacts free of obvious cracks with randomly distribution porosity at a rare level, and the powder specimens are irregular fragmented shapes with an average particles size of 5.41 μm. The average cation radius and interplanar spacings becomes larger compared with standard fluorite structure of CeO 2 due to the cation radius of La3+, Sm3+ and Nd3+ are larger than that of Ce4+, leading to an increase in lattice parameters of the HEFOs. In addition, the concentration of Ce3+ in the Ce cation is only 8.1 %, and the δ -value is calculated to be 0.3081 based on the content of all cations per mole of the substance, which indicates that the composition of the prepared specimen is (Ce 0.2 Zr 0.2 La 0.2 Sm 0.2 Nd 0.2)O 1.6919. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition is an important mechanism for developing fossil hydrogen energy. However, the research of imbibition micromechanisms and scaling methods in tight reservoirs with complex lithofacies remains limited. This study employed Nuclear magnetic resonance (NMR) monitoring to investigate imbibition at multiscale pores in tight sandy conglomerate samples. Then, a modified shut-in time-scale model was developed analyzing the imbibition modes and control factors. The results showed that the imbibition concludes three stages: suction, diffusion, and stable. The diffusion stage is crucial for promoting recovery. Two modes of imbibition in four lithofacies were distinguished: stable type (recovery>40 %) and sensitive type (recovery<20 %). Samples with medium permeability (0.2mD-0.6mD), bimodal pore distribution, and less illite/smectite mixed-layer (relative content<50 %) had high recovery. Nanopores provided foremost oil supply, while macropores facilitated fluid interchange. "Relay imbibition" from micropores to macropores was an important recovery mechanism. Hydrogen signals during clay expansion and microcracks propagation were identifiable by NMR-T2 after accounting for ferromagnets and temperature. The imbibition diffusion radius derived from T2 accumulation was found to modify the normalized time-scale model for complex lithofacies tight reservoirs. Consequently, the reasonable shut-in time for stable and sensitive reservoirs was concluded to be 32 and 11 days, respectively. [Display omitted] • Utilizing nuclear magnetic resonance (NMR) to study imbibition in tight reservoir. • Permeability, pore structure, and I/S content controlled imbibition recovery. • The mechanisms of imbibition in multiscale pores were revealed. • A new NMR parameter was found to describe the imbibition capacity. • A modified scaling model was proposed for complex lithological reservoirs. [ABSTRACT FROM AUTHOR]

Reef reservoirs are characterised by a complex structure of void space, which is a combination of intergranular porosity, fractures, and vuggy voids distributed chaotically in the carbonate body in different proportions. This causes great uncertainty in the distribution of porosity and permeability properties in the reservoir volume, making field development a complex and unpredictable process associated with many risks. High densities of carbonate secondary alterations can lead to the formation of zones with abnormally high porosity and permeability—high permeability streaks or super-reservoirs. Taking into account super-reservoirs in the bulk of the deposit is necessary in the dynamic modelling of complex-structure reservoirs because it affects the redistribution of filtration flows and is crucial for reservoir management. This paper proposes a method for identifying superreservoirs by identifying enormously high values of porosity and permeability from different-scale study results, followed by the combination and construction of probabilistic curves of superreservoirs. Based on the obtained curves, three probabilistic models of the existence of a superreservoir were identified: P10, P50, and P90, which were further distributed in the volume of the reservoir and on the basis of which new permeability arrays were calculated. Permeability arrays were simulated in a dynamic model of the Alpha field. The P50 probabilistic model showed the best history matching after one iteration. [ABSTRACT FROM AUTHOR]

Siliceous minerals of the Dengying Formation in the Gaoshiti–Moxi area in the central Sichuan Basin exhibit four types of quartz crystals (cryptocrystalline quartz, chalcedony, microcrystalline quartz, and megacrystalline quartz) and three structural types: cryptocrystalline, microcrystalline, and mosaic (laminated mosaic, window-hole interrupted mosaic, and arc-laminated mosaic). Siliceous minerals have a great influence on the storage performance of the reservoirs in the Dengying Formation. According to the petrophysical parameters of the Dengying Formation and porosity intersection diagrams, the siliceous dolomite and the reservoirs have low impedance characteristics, which makes it difficult to distinguish between them and leads to difficulties in the characterization and prediction of the reservoirs. The transverse wave velocity is favorable for reservoir characterization. Currently, the main method used to estimate the transverse wave velocity is petrophysical modeling, which establishes a relationship between the elastic and physical parameters of the reservoir. In this paper, the siliceous minerals in the dolomite in the study area are regarded as solid inclusions, and the calculation method of the rock matrix modulus is improved by using solid replacement. Then, an improved petrophysical model is constructed by combining the KT (Kuster–Toksöz) model, the DEM (Discrete Element Method) model, the Gassmann equation, and the Wood equation. The transverse wave velocity is estimated using the improved model under the constraint of the longitudinal wave velocity. The shapes of the transverse wave velocity curves obtained by the improved model and the deviations from the measured velocities are significantly better than those of the Xu–Payne model and other models. The results show that the improved model can effectively estimate the transverse wave velocity of the reservoir in this area, which provides a basis for future reservoir predictions in this area. [ABSTRACT FROM AUTHOR]

The porosity and permeability determine the reservoir quality of sedimentary rocks, which is fundamentally influenced by both depositional and diagenetic processes. The Jurassic carbonates are targeted in many regions for oil and gas exploration. The current study is carried out to elaborate on the diagenetic alterations and their effect on reservoir properties. A thick outcrop of the Jurassic Samana Suk Formation is studied in the Kahi section of Nizampur Basin Northwest Himalayas, Pakistan, to study and relate the trend of lithological variations and depositional settings. Field investigation revealed that the Samana Suk Formation is extensively distributed in the area and primarily made up of interbedded limestone and dolomite units. The original unaltered limestone has a thick-bedded and oolitic to bioclastic nature. Different types of dolomites have been recognized based on colour contrast and sedimentary features. Moreover, saddle dolomite cement, calcite cementation, and mechanical and chemical compaction have also been observed. The petrographic studies show different types of diagenetic alterations that affected the Samana Suk Formation, including micritization, bioturbation, mechanical and chemical compaction in the form of fractures and stylolites, various calcite cementation, which includes the various cement types that range from isopachous, blocky, granular equant, fibrous, and dog tooth cementation, along with dissolution that occurred in different diagenetic realms. Pyritization was rarely observed. Moreover, different phases of dolomites were identified, ranging in size and shape, i.e., finely crystalline to coarse crystalline and planar euhedral to non-planar anhedral. The stable oxygen isotope values of these dolomites show depletion from original marine signatures and suggest burial-related fault-controlled dolomitization events. Overall, diagenetic processes like dissolution, fracturing and dolomitization increased the reservoir potential. On the contrary, the overburden and cement precipitation result in a decrease in the reservoir properties. [ABSTRACT FROM AUTHOR]

With the gradual depletion of natural sand due to over-exploitation, alternative building materials, such as manufactured sand aggregate (MSA), have attracted much attention. In order to interpret the evolution of pore structure and fractal characteristics in MSA mortar over long-term water saturation, the 1H low-field nuclear magnetic resonance (LF-NMR) relaxation method was used to investigate the temporal evolution of the pore structure in five single-graded MSA mortars and synthetic-graded mortars with small amplitudes in particle size. MSA presents a fresh rock interface characterized by a scarcity of pores, which significantly reduces the porosity of the mortar. The surface-to-volume ratio (SVR) is employed for characterizing the MSA gradation. Through an analysis of parameters, such as total porosity, pore gradation, pore connectivity, and pore fractal dimension of mortar, a correlation model between pore structure parameters and aggregate SVR is constructed. The fractal characteristics of pores and their variations are discussed under three kinds of pore gradations, and the correlation model between fractal dimension and porosity is established. These results demonstrate the high impermeability and outstanding corrosion resistance of synthetic-graded mortar. The fractal model of the pore structure evolution of MSA mortar has a guiding effect on the pore distribution evolution and engineering permeability evaluation of MSA mortar in engineering. [ABSTRACT FROM AUTHOR]

The evaluation of reservoir quality was accomplished on the Late Paleocene to Early Eocene Narimba Formation in Bass Basin, Australia. This study involved combination methods such as petrophysical analysis, petrography and sedimentological studies, reservoir quality and fluid flow units from derivative parameters, and capillary pressure and wetting fluid saturation relationship. Textural and diagenetic features are affecting the reservoir quality. Cementation, compaction, and presence of clay minerals such as kaolinite are found to reduce the quality while dissolution and secondary porosity are noticed to improve it. It is believed that the Narimba Formation is a potential reservoir with a wide range of porosity and permeability. Porosity ranges from 3.1% to 25.4% with a mean of 15.84%, while permeability ranges between 0.01 mD and 510 mD, with a mean of 31.05 mD. Based on the heterogenous lithology, the formation has been categorized into five groups based on permeability variations. Group I showed an excellent to good quality reservoir with coarse grains. The impacts of both textural and diagenetic features improve the reservoir and producing higher reservoir quality index (RQI) and flow zone indicators (FZI) as well as mostly mega pores. The non-wetting fluid migration has the higher possibility to flow in the formation while displacement pressure recorded as zero. Group II showed a fair quality reservoir with lower petrophysical properties in macro pores. The irreducible water saturation is increasing while the textural and digenetic properties are still enhancing the reservoir quality. Group III reflects lower quality reservoir with mostly macro pores and higher displacement pressure. It may indicate smaller grain size and increasing amount of cement and clay minerals. Group IV, and V are interpreted as a poor-quality reservoir that has lower RQI and FZI. The textural and digenetic features are negatively affecting the reservoir and are leading to smaller pore size and pore throat radii (r35) values to be within the range of macro, meso-, micro-, and nano pores. The capillary displacement pressure curves of the three groups show increases reaching the maximum value of 400 psia in group V. Agreement with the classification of permeability, r35 values, and pore type can be used in identifying the quality of reservoir. [ABSTRACT FROM AUTHOR]

A mesoporous cobalt ferrite nanostructure was prepared by a green chemistry approach using Pimpinella anisum extract for Cd (II) ions elimination from an aqueous medium. The metal ions adsorption was explored under varying operating conditions, comprising of the pH, initial adsorbate concentration, and contact time. The synthesized sorbent was characterized by various techniques where the XRD data verified a ferrite structure of ≈25 nm crystallite size and the EDX elemental analysis affirmed the presence of the corresponding elements. The CoFe2O4 established porosity characteristic of 10.8 m2 g−1 BET-specific surface area and 0.023 cm3 g−1 pore volume values. Batch mode experiments ascertained that the Cd (II) ions uptake was pH-dependent, with peak removal of 170 mg/g accomplished at pH = 5. The adsorption process of the metal ions onto the mesoporous nanomaterial surface fitted well with the Langmuir isotherm and pseudo-second-order kinetics models. The mechanistic aspects indicated the role of intra-particle and film diffusion in the adsorption process. The adsorbent could efficiently remove the pollutant up 74.3 % to four cycles of successful regeneration. This investigation endorsed that CoFe2O4 might be potent candidate for heavy metals from aqueous systems. [ABSTRACT FROM AUTHOR]

The 2.02 billion year old Vredefort impact structure in South Africa offers a unique opportunity to study large‐scale impact processes on Earth. Vredefort's large size (∼250 km in diameter) and eroded topography provides the opportunity to study the effects of shock physics at depth and post‐formation hydrothermal alteration. In this work, we simulate the formation of the Vredefort structure building upon recent shock physics (iSALE) simulations. We expand those simulations to cover a wider range of input conditions, and compute impact‐driven porosity and permeability. The latter quantities are used to perform fluid mobility simulations (HYDROTHERM). We find that the Vredefort event produced significant impact‐generated porosity (up to 30%) in an annulus from about 50 to 100 km from the center and up to several kilometers in depth. The corresponding estimated permeability (up to 10−12 m2) would have allowed for large scale subsurface fluid flows. Our hydrothermal calculations show that the Vredefort impact event could have generated a complex crustal fluid pattern within the crater rim that lasted for hundreds of thousand years, with localized flow concentration regions, opening a new interpretation for the mobilization and location of the ore deposits in the Witwatersrand basin. The combined approach utilizing impact and hydrothermal simulations constitute a powerful tool to understand geochemical processes at Vredefort, as well as to assess the ability of large impacts to drive crustal chemistry with far‐reaching consequences for the prebiotic evolution of the early Earth. Key Points: Vredefort impact event generated widespread crustal porosity and permeabilityPost‐impact hydrothermal alteration lasted for 100s of thousands of yearsLarge‐scale impacts are an important source of crustal fluid mobility in the early Earth [ABSTRACT FROM AUTHOR]

The study of carbonate petrography is essential for understanding reservoir properties and the quality of rock formations. High-resolution cathodoluminescence spectroscopy and optical microscopy were used to determine the impact of cement on the porosity evolution of carbonate rocks of the Kurra Chine Formation at Sirwan Valley, Northern Iraq. This study represents the first-ever attempt to investigate sedimentology at this location. A total, of 183 thin-section slides, 18 X-Ray Diffraction (XRD) samples, 14 Scanning Electron Microscope (SEM) samples, and 6 Cathodoluminescence (CL) samples were analyzed from the outcrop section of the Kurra Chine Formation. Four types of dolomite textures are recognized and classified based on the crystal size distribution and crystalboundary shape. The porosity within Kurra Chine Formation includes primary and secondary porosity, with the majority of primary porosity being occluded by cementation. Cathodoluminescence analysis revealed two phases of calcite cement in the Kurra Chine Formation. The first phase (C1), is characterized by weak-zoned blocky calcite, displaying a dull luminescence with typical homogenous red color, which fills most of the interparticle and moldic pores. The second type of calcite cement (C2) is ghost-zoned calcite exhibiting red to slight orange luminesces interfingering with dolomite cement. XRD analysis indicated a predominant of calcite and common dolomite. SEM analysis revealed the predominance of secondary porosity occurring within fractures of the dolomite. [ABSTRACT FROM AUTHOR]

Petrophysical interpretation and optimal correlation extraction of different measurements require accurate well log depth matching. We have developed a supervised multimodal machine learning alternative for the task of simultaneously matching raw logging while drilling and electrical wireline logging logs. Seven one‐dimensional convolutional neural networks are trained using different log measurements: gamma‐ray, resistivity, P‐ and S‐wave sonic, density, neutron and photoelectric factors, and their depth shift estimates are aggregated using different multimodal late fusion strategies. We test the late fusion average, late fusion weighted average, late fusion with linear and nonlinear learners and model‐level fusion. Depth matching results using the different fusion strategies applied to two unseen wells are compared using visual inspection and the mean Pearson correlation. All models perform well, increasing the correlation after depth matching. Late fusion weighted average achieves the highest scores for all log types. The late fusion weighted average results are compared to a cross‐correlation user‐assisted workflow and manual depth matching for validation. In general, the convolutional neural network fused method exhibits a lower performance than the traditional methods. For one of the wells, the cross‐correlation shows higher correlation values than the other methods but for the second well the manual depth match performs best. However, the differences in Pearson correlation values are small ranging from 0.01 to 0.1. The manual depth match performs very well for the sonic logs, which tend to require slightly larger depth shifts than the other measurements, thus a common depth shift might not always be suitable. Although our convolutional neural network fused approach is limited to estimating bulk shifts and uses constant fusion weights, its performance is similar to that of more time‐consuming methods. Our approach might be substantially improved by including dynamic shifts (stretch/squeeze) and depth‐dependent fusion weights via long‐short‐term memory recurrent neural networks. [ABSTRACT FROM AUTHOR]

This study presents an integration of various approaches to delimit potential play elements and prospects in the 'Soka' Field Coastal swamp, Niger Delta. This study is a multiple cross-disciplinary work that combined sequence stratigraphy and petrophysical principles to delineate potential reservoirs, seals, and the source rock in the study area. One genetic sequence was identified using seismic sequence stratigraphy and well logs data; the depositional key surfaces, system tracts and their various parasequences were mapped out with the aid of biostratigraphic makers. The result for this study showed that there are two major reservoirs sand that contained hydrocarbon from the well log readings, named top-3 and top-10 reservoirs, regardless of other reservoirs that were encountered. Three major system tracts were encountered, the progradational stacking sediment package of both HST and LST and transgressive sand Package of TST. The depositional environments are of fluvial and deltaic or shallow marine interaction. The following environments were predicted from their various log signatures; they include pro-delta, trangressive marine shelf, slope fan, and tidal channel deposits with this corresponding lithology: shale, sand, heterolith and shaley sand respectively. From the seismic interpretation, it was discovered that this field is highly faulted. The petrophysical analysis revealed that Soka-002 and Soka-004 amongst other wells have much and better reservoir than the rest wells. The average effective porosity is between 20-25%, the average net-to-gross ratio is about 75-75% and hydrocarbon saturation ranges from 65-95%. From the petrophysical crossplot it was discovered that the area of study has good reservoirs capable of habouring hydrocarbon, also the volumetrics estimation showed that Soka-002 and Soka-004 has more and better reservoir zones than the other wells in the field. Generally, the results from sequence stratigraphy, petrophysical analysis and volumetric estimation showed that the study area is highly petroliferous and viable for any economical investments since most of the reservoirs are saturated with either oil or gas. [ABSTRACT FROM AUTHOR]

Reservoir characterization entails mapping properties such as lithology, fluid type, porosity and permeability, to describe reservoir quality and identify areas for the location of new wells for optimum production. In this study, we test the reliability of rock-physics modelling and model-based post-stack seismic inversion for characterizing reservoir rocks located within the 'Rhoda' field, onshore Niger Delta Basin, Nigeria. The aim is to accurately discriminate lithology and estimate reservoir properties for accurate prediction of new prospective areas within the field of interest. Unlike some conventional inversion and geomodelling algorithms, which are probabilistic, model-based post-stack seismic inversion is favoured for its sensitivity in resolving thin-bed tuning for increased stratigraphic resolution and reservoir property prediction. More so, it gives satisfactory results, even with limited well control and fair to poor seismic quality, as will be shown in this study. On the basis of gamma-ray and resistivity log signatures, two reservoir sands, dubbed D6000 and D7000, were identified in the field of study. Along the eastern direction, well correlation revealed a significant net sand reduction. Within the reservoirs of interest, petrophysical parameters such as water saturation (Sw), porosity (Ø), and shale volume (Vsh) were evaluated. With high Ø and low Sw and Vsh values, these reservoirs were classified as good quality reservoirs. Crossplots of well-log properties such as density vs acoustic impedance, velocity ratio vs acoustic impedance, gamma-ray vs density, and gamma-ray vs acoustic impedance showed lithologies and pore fluids such as hydrocarbon sand, brine-sand, and shale. The model-based post-stack seismic inversion results revealed a lateral distribution of hydrocarbon and brine sands characterized by low and moderate acoustic impedance values, respectively. The low values of acoustic impedance slice and seismic horizon attributes (instantaneous phase and frequency) identified away from the drilled locations imply the presence of hydrocarbon-charged sands, which are potential prospects for future exploitation. This study therefore, shows the effectiveness of rockphysics-based modelling and model-based post-stack seismic inversion in the characterization of reservoir sands within the Niger Delta Basin and can be applied in other provinces around the world. [ABSTRACT FROM AUTHOR]

Porosity is one of the most important petrophysical parameters, studied in the subject of reservoir characterization. Determining porosity and how it changes in hydrocarbon reservoirs is an important issue that has been addressed in various researches. In this research, Poro-Acoustic Impedance (PAI) is introduced as an extended form of Acoustic Impedance (AI). The difference between PAI and AI is related porosity that is directly involved in the PAI. The inclusion of porosity data in the PAI formula made porosity effective in forward modeling and inversion of seismic data. The use of PAI in the forward modeling of synthetic models increases the contrast between the subsurface layers, and the contrast increases twice as compared to the AI. Band Limited Recursive Inversion (BLRI) algorithm is used for inversion of synthetic seismograms and model-based algorithm is used for real seismic data inversion. For real data, due to the existence of well data, seismic horizons and geological information, using the basic model method for inversion is more accurate. The main difference between inversion using PAI and AI is that changes in porosity can be seen directly in the results of PAI inversion. The correlation of porosity with PAI and AI is -0.93 and -0.85, respectively, which shows that porosity has a stronger relationship with PAI. The use of PAI can be a quick and simple solution to understand porosity changes in hydrocarbon reservoirs and increase the accuracy of porosity determination in reservoirs to a great extent. [ABSTRACT FROM AUTHOR]

The early Cretaceous sand intervals of Lower Goru Formation (LGF) are significant reservoir for hydrocarbons and are situated in study area of Sawan gas field, Middle Indus Basin, Pakistan. This integrated study focuses on the development of stratigraphic traps and reservoir geometries in paleo-depositional environment through sequence stratigraphic and diagenetic analysis of productive Lower Goru sandstone. The datasets of well-logs from five wells (Sawan-1, Sawan-2, Sawan-3, Judge-1, and Nara-1), core samples from two wells (Sawan-1 and Sawan-2) and 2D seismic section (line: PSM96-133) are used in this study. The key system tracts including lowstand, transgressive, and highstand system tracts are identified with several progradational and retrogradational parasequences. The bounding stratigraphic surfaces are identified as sets of onlaps and downlaps unveiling different episodes of rise and fall in sea level with different sedimentation conditions. A depositional model is generated to map the paleo-environment of the reservoir by integrating the results of stratigraphic analysis. The log trends and seismic stratigraphic analysis showed the thickening trend of productive C-sand interval towards the eastern direction followed by gradual thinning in the middle part and shale-out trend towards the south and west part of the area. This indicates that the paleo-depositional direction was from east to west in shallow marine settings. The petrography and diagenesis results reveal that reservoir sands are iron chlorite-cemented sublitharenites to lithic arenites. The porosity and permeability of the reservoir is preserved due to a high amount of early diagenetic pore-lining iron chlorite, which commonly coats the surface of the quartz grains. The facies depositional environment is a wave dominated lowstand shelf edge delta system in which proximal delta front sands constitute the best reservoir. The outcomes of this research hold significant promise for advancing the comprehension of diagenetic processes and their influence on reservoir properties within the Lower Goru sandstone and its surrounding regions. [ABSTRACT FROM AUTHOR]

Traditional research on apparent permeability in shale reservoirs has mainly focussed on effects such as poromechanics and porosity-assisted adsorption layers. However, for a more realistic representation of field conditions, a comprehensive multi-scale and multi-flowing mechanism model, considering the fracturing process, has not been thoroughly explored. To address this research gap, this study introduces an innovative workflow for dynamic permeability assessment. Initially, an accurate description of the pore size distribution (PSD) within three major mineral types in shale is developed using focussed ion beam-scanning electron microscopy (FIB-SEM) and nuclear magnetic resonance (NMR) data. Subsequently, an apparent permeability model is established by combining the PSD data, leading to the derivation of dynamic permeability. Finally, the PSD-related dynamic permeability model is refined by incorporating the effects of imbibition resulting from the fracturing process preceding shale gas production. The developed dynamic permeability model varies with pore and fracture pressures in the shale reservoir. The fracturing process induces water blockage, water-film formation, and water-bridging phenomena in shale, requiring additional pressure inputs to counteract capillary effects in hydrophilic minerals in shale, But also increases the overall permeability from increasing permeability at larger scale pores. Unlike traditional reservoirs, the production process commences when the fracture is depleted to 1–2 MPa exceeds the pore pressure, facilitated by the high concentration of hydrophobic organic matter pores in shale, this phenomenon explains the gas production at the intial production stage. The reduction in adsorption-layer thickness resulting from fracturing impacts permeability on a nano-scale by diminishing surface diffusion and the corresponding slip flow of gas. this phenomenon increases viscous-flow permeability from enlarged flow spacing, but the increased viscous flow does not fully offset the reduction caused by adsorbed-gas diffusion and slip flow. In addition to the phenomena arising from various field conditions, PSD in shale emerges as a crucial factor in determining dynamic permeability. Furthermore, considering the same PSD in shale, under identical pore spacing, the shape factor of slit-like clay minerals significantly influences overall permeability characteristics, much more slit-shaped pores(higher shape factor) reduce the overall permeability. The dynamic permeability-assisted embedded discrete fracture model (EDFM) showed higher accuracy in predicting shale gas production compared to the original model. [ABSTRACT FROM AUTHOR]

A binary, three-dimensional (3D), foldable, Metal–Organic Framework (MOF) of formula {[trans-Ni(H2O)2(μ-4,4′-bpy)2](ClO4)2}n (1), with CdSO4 (65 8), cds, topology, based on four-connected (4-c) square-planar single Ni2+ ion nodes and two-connected (2-c) linear rigid 4,4′-bipyridine (4,4′-bpy) ligands, was synthesized and structurally characterized via single crystal X-ray crystallography. The 41° dihedral angle between two distinct coordination environments within the 3D network of 1 produced the self-dual topology of Ni2+ nodes. Two rectangular 1D channels ran parallel to the crystallographic a-axis and b-axis, respectively, creating a 44.2% volume porosity, probed by gas (N2, CO2, and H2) sorption studies. The PXRD, FT-IR, Raman, EDS, and SEM methods were employed for the study of 1. A thermogravimetric analysis (TGA) showed that coordinated water molecules were readily removed upon heating, whereas the 3D lattice remained intact up to 370 °C. [ABSTRACT FROM AUTHOR]

The longevity of thermally sprayed ceramic coatings is often difficult to achieve in corrosive environments. In this paper, an alternating sealing coating technology was used to seal supersonic plasma sprayed Al2O3 coatings. Scanning electron microscopy (SEM) and X-ray diffraction (XRD) were used to characterize the coating microstructure of Al2O3 coatings and seal coats. The corrosion behavior of alternating sealing coating, traditional sealed coating, and spray coating at 5 wt.% NaCl was studied by the electrochemical test method (dynamic polarization) and immersion corrosion experiments. The results show that the alternating sealing coating is better in preventing the production of through holes and hindering the inward diffusion of corrosive media than traditional sealed coatings, and further increases the thickness of the sealing layer. Compared with the traditional sealing coating, the porosity of alternating sealing coating is decreased by 70.5%, the corrosion potential is increased by 74 mV, and the corrosion current density is decreased by about 78%, which confers better long-term corrosion resistance. [ABSTRACT FROM AUTHOR]

Petrophysical evaluation and hydrocarbon prospectivity of Osaka Field in Niger Delta Nigeria was carried out with the aim of identifying the reservoir and estimating the hydrocarbon-bearing potentials of the reservoirs. Composite suite of well logs comprising gamma ray, resistivity, neutron porosity, density porosity and sonic logs were acquired from an oil producing company. Four wells, Osaka well 001, well 002, well 003 and well 004 were used for the exercise. The logs were uploaded into the Petrel Workflow software. Three reservoirs R1, R2 and R3 were correlated and petrophysical parameters (porosity, permeability, water saturation, irreducible water saturation, and hydrocarbon saturation and formation factors) computed. Hydrocarbon discrimination was done using the overlay of the neutron and the density porosity logs. The petrophysical analysis result showed that the water saturation varies from 15% to 46% in well 1, 38% to 46% in well 2, 40% to 65% in well 3 and 26% to 40% in well 4. The irreducible water saturation also varies from 4% to 8% in well 1, 6% to 8% on well 2, 5% to 7% in well 3, 5% to 7% in well 4. Based on the results obtained from the hydrocarbon saturation which vary from 53% to 84% in well 1, 54% to 62% in well 2, 40 to 69% in well 3 and 60% to 74% in well 4. It is concluded from the study that reservoir rocks in the studied wells in Osaka field generally are prospective and could be exploited for exploration purposes. [ABSTRACT FROM AUTHOR]

Biochar is an engineered carbon-rich substance used for soil improvement, environmental management, and other diverse applications. To date, the understanding of how biomass affects biochar microstructure has been limited due to the complexity of analysis involved in tracing the changes in the physical structure of biomass as it undergoes thermochemical conversion. In this study, we used synchrotron x-ray micro-tomography to visualize changes in the internal structure of biochar from diverse feedstock (miscanthus straw pellets, wheat straw pellets, oilseed rape straw pellets, and rice husk) during pyrolysis by collecting a sequence of 3D scans at 50 °C intervals during progressive heating from 50 °C to 800 °C. The results show a strong dependence of biochar porosity on feedstock as well as pyrolysis temperature, with observed porosity in the range of 7.41–60.56%. Our results show that the porosity, total surface area, pore volume, and equivalent diameter of the largest pore increases with increasing pyrolysis temperature up to about 550 °C. The most dramatic development of pore structure occurred in the temperature range of 350–450 °C. This understanding is pivotal for optimizing biochar's properties for specific applications in soil improvement, environmental management, and beyond. By elucidating the nuanced variations in biochar's physical characteristics across different production temperatures and feedstocks, this research advances the practical application of biochar, offering significant benefits in agricultural, environmental, and engineering contexts. [ABSTRACT FROM AUTHOR]

Changing stress regimes control fracture network geometry and influence porosity and permeability in carbonate reservoirs. Using outcrop data analysis and a displacement-based linear elastic finite element method, we investigate the impact of stress-regime change on fracture network permeability. The model is based on fracture networks, specifically fracture sub-structures. The Latemar, predominantly affected by subsidence deformation and Alpine compression, is taken as an outcrop analogue for an isolated (Mesozoic) carbonate buildup with fracture-dominated permeability. We apply a novel strategy involving two compressive boundary loading conditions constrained by the study area's NW-SE and N-S stress directions. Stress-dependent heterogeneous apertures and effective permeability were computed by (i) using the local stress state within the fracture sub-structure and (ii) running a single-phase flow analysis considering the fracture apertures in each fracture sub-structure. Our results show that the impact of the modelled far-field stresses at (i) subsidence deformation from the NW-SE and (ii) Alpine deformation from N-S increased the overall fracture aperture and permeability. In each case, increasing permeability is associated with open fractures parallel to the orientation of the loading stages and with fracture densities. The anisotropy of permeability is increased by the density and connectedness of the fracture network and affected by shear dilation. The two far-field stresses simultaneously acting within the selected fracture sub-structure at a different magnitude and orientation do not necessarily cancel out each other in the mechanical deformation modelling. These stresses affect the overall aperture and permeability distributions and the flow patterns. These effects--potentially ignored in simpler stress-dependent permeability--can result in significant inaccuracies in permeability estimation. [ABSTRACT FROM AUTHOR]

To understand the occurrence state of fracturing fluid in shale gas matrix-fracture system, an experimental method for evaluating fracturing fluid flow characteristics in matrix-fracture system was established. By using Nuclear Magnetic Resonance method, the flow characteristics of fracturing fluid were investigated from three processes of filtration, well shut-in and flowback. The T2 spectrum of fracturing fluid flow process and fracturing fluid saturation in matrix-fracture core model were clarified. The results demonstrate that the peak area of T2 spectra increases gradually during the filtration process, and the fracturing fluid quickly fills the fractures and matrix pores. During the well shut-in process, the fracturing fluid gradually flows from the fracture space to the matrix pores, and the signal of the matrix pores increases by 50.5%. During the flowback process, fracturing fluid flows out of the matrix and fracture. And when it reaches a stable state, the peak signal in the fracture decreases by 64.5% and the matrix signal reduces by 18.8%. The better the porosity and permeability characteristics of the core, the more likely the fracturing fluid is to stay in the formation and cannot be discharged. This paper would contribute to basic parameters for shale gas fracturing design and production strategy optimization. [ABSTRACT FROM AUTHOR]

We study the reflection and transmission (R/T) characteristics of inhomogeneous plane waves at the interface between two dissimilar fluid-saturated thermoporoelastic media at arbitrary incidence angles. The R/T behaviors are formulated based on the classic Lord–Shulman (LS) and Green–Lindsay (GL) heat-transfer models as well as a generalized LS model, respectively. The latter results from different values of the Maxwell-Vernotte-Cattaneo relaxation times. These thermoporoelastic models can predict three inhomogeneous longitudinal (P1, P2, and T) waves and one shear (S) wave. We first compare the LS and GL models for the phase velocities and attenuation coefficients of plane waves, where the homogeneous wave has a higher velocity but weaker thermal attenuation than the inhomogeneous wave. Considering the oil–water contact, we investigate R/T coefficients associated with phase angles and energy ratios, which are formulated in terms of incidence and inhomogeneity angles, with the latter having a significant effect on the interference energy. The proposed thermoporoelastic R/T model predicts different energy partitions between the P and S modes, especially at the critical angle and near grazing incidence. We observe the anomalous behavior for an incident P wave with the inhomogeneity angle near the grazing incidence. The energy partition at the critical angle is mainly controlled by relaxation times and boundary conditions. Beyond the critical angle, the energy flux predicted by the Biot poroelastic and LS models vanishes vertically, becoming the opposite for the GL and generalized LS models. The resulting energy flux shows a good agreement with the R/T coefficients, and they are well proven by the conservation of energy, where the results are valuable for the exploration of thermal reservoirs. [ABSTRACT FROM AUTHOR]

Fluid‐induced earthquakes adversely affect industrial operations like hydraulic fracturing (e.g., 4.6 Mw in Alberta, Canada) and enhanced geothermal systems (e.g., 5.5 Mw in Pohang, South Korea). Identifying all underlying physical processes contributing to fluid‐induced seismicity presents an open challenge. Recent work reports signatures of event‐event triggering or aftershocks—common for tectonic settings—within the context of fluid‐induced seismicity. Here, we investigate the underlying potential cause of these field observations from a modeling perspective. We extend a novel conceptual model to simulate the characteristics of crustal rheology and stress interactions in a porous medium by combining viscoelastic effects with fluid diffusion and invasion percolation associated with a point source. Our model successfully reproduces realistic aftershock behavior and statistical properties similar to those resulting from tectonic loading indicating that the statistical properties of aftershocks are unaffected by the fluid injection rate. At the same time, the Gutenberg‐Richter relation, the spatial footprint of fluid‐induced events and their dependence on the permeability field are largely unaltered by the viscoelasticity of the medium and the aftershocks it causes. Furthermore, we investigate the impact of varying fluid injection rates on detecting aftershocks and event‐event triggering sequences during viscoelastic stress redistribution. We find that when the injection rate is sufficiently high, aftershock detection and recovery of their statistical properties are only feasible when the underlying internal stress redistribution is directly accessible. This could explain why aftershocks have not been reported in some field studies of fluid‐induced seismicity. Plain Language Summary: Fluid‐induced earthquakes are an unintended consequence of industrial activities such as enhanced geothermal systems and hydraulic fracturing. These operations involve injecting high‐pressure fluids into the Earth's crust to improve the permeability of deep geothermal reservoirs or enhance oil and gas extraction from rock formations, respectively. The resulting seismic activity has raised concerns among the industry and residents. Similar to tectonic earthquakes, some cases of fluid‐induced earthquakes have shown the presence of aftershocks during or after field operations, which need to be taken into account for seismic hazard assessments. In particular, understanding the fundamental physical mechanisms that connect fluid injection and earthquakes is crucial to assess seismic hazards correctly. Here, we extend a conceptual model of fluid‐induced earthquakes by incorporating a slow mode of stress transfer. In this case, aftershocks occur and our results show that the aftershock behavior in fluid‐induced settings resembles that of tectonic aftershocks. We also find that the fluid injection rate does not affect the characteristics of aftershocks. However, detecting aftershocks and recovering their characteristics depends on the accessibility of the internal stress dynamics. Our findings shed light on the behavior of fluid‐induced earthquakes and why aftershocks may not be detected in some field cases. Key Points: Incorporating viscoelasticity in models of fluid‐induced seismicity leads to aftershock triggering, independent of the injection rateGutenberg‐Richter relation and the spatial footprint of fluid‐induced events and its dependence on the permeability field remain largely unalteredWhen fluid injection rates are high, aftershock detection is only feasible when the internal stress field is accessible [ABSTRACT FROM AUTHOR]

The Golden (British Columbia, Canada) meteorite fall occurred on October 4, 2021 at 0534 UT with the first recovered fragment (1.3 kg) landing on an occupied bed. The associated fireball was recorded by numerous cameras permitting reconstruction of its trajectory and orbit. The fireball entered the atmosphere at a 54° angle from the horizontal at a speed of 18 km s−1. The fireball reached a peak brightness of −14, having first become luminous at a height of >84 km and ending at 18 km altitude. Analysis of the infrasonic record of the bolide produced an estimated mass of 78−65+157 kg while modeling of the fireball light curve suggests an initial mass near 70 kg. The fireball experienced a major flare near 31 km altitude where more than half its mass was lost in the form of dust and gram‐sized fragments under a dynamic pressure of 3.3 MPa. The strength and fragmentation behavior of the fireball were similar to those reported for other meteorite‐producing fireballs (Borovička et al., 2020). Seven days after the fireball occurred, an additional 0.9 kg fragment was recovered during the second day of dedicated searching guided by initial trajectory and dark flight calculations. Additional searching in the fall and spring of 2021–2022 located no additional fragments. The meteorite is an unbrecciated, low‐shock (S2) ordinary chondrite of intermediate composition, typed as an L/LL5 with a grain density of ~3530 k gm−3, an average bulk density of 3150 kg m−3 and calculated porosity of ~10%. From noble gas measurements, the cosmic ray exposure age is 25 ± 4 Ma while gas retention ages are all >2 Ga. Short‐lived radionuclides and noble gas measurements of the pre‐atmospheric size overlap with estimates from infrasound and light curve modeling producing a preferred pre‐atmospheric mass of 70–200 kg. The orbit of Golden has a high inclination (23.5°) and is consistent with delivery from the inner main belt. The highest probability (60%) of an origin is from the Hungaria group. We propose that Golden may originate among the background S‐type asteroids found interspersed in the Hungaria region. The current collection of 18 L/LL—chondrite orbits shows a strong preference for origins in the inner main belt, suggesting multiple parent bodies may be required to explain the diversity in CRE ages and shock states. [ABSTRACT FROM AUTHOR]

CM carbonaceous chondrites can be used to constrain the abundance and H isotopic composition of water and OH in C‐complex asteroids. Previous measurements of the water/OH content of the CMs are at the higher end of the compositional range of asteroids as determined by remote sensing. One possible explanation is that the indigenous water/OH content of meteorites has been overestimated due to contamination during their time on Earth. Here we have sought to better understand the magnitude and rate of terrestrial contamination through quantifying the concentration and H isotopic composition of telluric and indigenous water in CM falls by stepwise pyrolysis. These measurements have been integrated with published pyrolysis data from CM falls and finds. Once exposed to Earth's atmosphere CM falls are contaminated rapidly, with some acquiring weight percent concentrations of water within days. The amount of water added does not progressively increase with time because CM falls have a similar range of adsorbed water contents to finds. Instead, the petrologic types of CMs strongly influence the amount of terrestrial water that they can acquire. This relationship is probably controlled by mineralogical and/or petrophysical properties of the meteorites that affect their hygroscopicity. Irrespective of the quantity of water that a sample adsorbs or its terrestrial age, there is minimal exchange of H in indigenous phyllosilicates with the terrestrial environment. The falls and finds discussed here contain 1.9–10.5 wt% indigenous water (average 7.0 wt%) that is consistent with recent measurements of C‐complex asteroids including Bennu. [ABSTRACT FROM AUTHOR]

Natural tuff samples in western Anatolia (Türkiye) originating from Miocene rhyolitic–pyroclastic rocks with >80 wt.% heulandite/clinoptilolite zeolites were investigated for their surface characteristics determined according to nitrogen adsorption after degassing at 150°C (specific surface area, pore volume and pore diameter). Additionally, these surface characteristics were correlated with the cationic compositions of the heulandite/clinoptilolite group minerals. The examined samples were characterized by two main pore diameters that were not related to specific surface area and pore volume but were partially related to the types and occupancy of extra-framework cations. One set of samples has a pore diameter of ~24 Å, total cation content (Na + K + Ca + Mg) ranging from 3.46 to 4.40 and a (Na + K)/(Ca + Mg) ratio ranging from 0.34 to 0.92. The total cation contents and (Na + K)/(Ca + Mg) ratios of the remaining samples with a pore diameter of ~37 Å are 4.30–5.08 and 1.48–2.85, respectively. After degassing at 300°C, there is a slight difference in the pore diameters of these two sets of samples (~37 and 38 Å). The pore sizes of the samples with a (Na + K)/(Ca + Mg) ratio < 1 (heulandite composition) increased from 24 to 36–38 Å with increasing degassing temperature, whereas the pore sizes of the samples with a (Na + K)/(Ca + Mg) ratio > 1 (clinoptilolite composition) increased from 37 to only 38–39 Å. However, there is no correlation between the Si/Al ratios and the cation-exchange capacities of the samples and their surface characteristics obtained by degassing at the two temperatures. [ABSTRACT FROM AUTHOR]

Estimation of reservoir properties from seismic data suffers from non-unique solutions. A workflow based on the numerical reformulation of a laboratory-based rock physics model may reduce the non-uniqueness. This study attempts to integrate seismic and well log data of relatively unexplored parts of Upper Assam (UA) basin using inversion driven by laboratory based rock physics model. The laboratory-based rock physics model was developed based on experimental measurements conducted on rock cores from Tipam and Barail formations of the basin. Seismic inversion analysis was performed in OpendTect, an open-source software on post-stack seismic data to derive the acoustic impedance (AI) using coloured inversion. A multilayered feed-forward neural network was developed to spatially populate different petrophysical properties. Laboratory-based correlations between AI, density, porosity were utilised for the AI model from which velocity was computed using multivariate rock physics equation. This derived velocity value was transformed to AI and subsequently trained with well log to populate density (2.23-2.73 gm/cc) and porosity (7-28%) for the entire survey area. A reasonable to high correlation is obtained between bulk density and porosity derived by NN using well log and that derived by laboratory-based model (r = 0.78, 0.91 for Barail and 0.95, 0.94 for Sylhet formation). Thus, integrating datasets of different scale from seismic to core with well log data using neural network helps to derive more realistic models that helps in quantitative decision analysis. [ABSTRACT FROM AUTHOR]

The objective of petrophysical studies is to assess the quality of hydrocarbon reservoir layers and to zone the reservoir for identifying optimal zones for exploitation and informed development of oil fields. In some regions, there are zones that exhibit lower electrical resistivity values than their actual values. These low-resistivity zones are often identified through petrophysical investigations and conventional well logs, where water saturation levels are estimated higher due to their reduced resistivity. These zones, despite their hydrocarbon potential, are often neglected during production cycles. To overcome this challenge, nuclear magnetic resonance (NMR) logging tools can be employed to provide accurate estimations of free fluid saturation, irreducible fluid saturation, permeability, and effective porosity in such low-resistivity zones, making them more identifiable. In this article, we utilized conventional well logs and NMR log from the A well in the Sarvak reservoir of one of the oil fields in southwestern Iran. Based on the obtained results, depth interval 9586 to 9783 ft in the Sarvak Formation, along with two intervals (10661-10815 ft) and (10830-11063 ft) in the Int zone, were identified as potential low-resistivity zones in the reservoir. By analyzing the high-resistivity logs, water saturation percentage was calculated for these zones, and the results from NMR logging confirmed their favorable reservoir potential (e.g., free fluid saturation, effective porosity, viscosity, and permeability). Furthermore, to extend the petrophysical parameters, such as free fluid saturation and porosity, throughout the entire hydrocarbon field, various approaches including single-attribute methods, multi attribute methods, and neural networks were evaluated. The neural network method demonstrated higher accuracy in determining the parameters. Ultimately, the values of porosity and free fluid saturation in the study area were determined with 91% and 95.8% matching accuracy, respectively. The final results were validated using unseen data, and the high precision of the obtained results was confirmed. [ABSTRACT FROM AUTHOR]

Consistency in the petrophysical and elastic properties is very critical for the characterization in low to intermediate (tight) porosity sandstone reservoirs. In this case study, we have applied an iterative and integrated workflow that provided consistency between the petrophysical and elastic properties using rock physics modeling scheme for the quantitative characterization of the low to intermediate porosity reservoir of Cretaceous (Pab) sandstone reservoir of the mature field in middle Indus basin of Pakistan. Before petrophysics and rock physics modeling (RPM), the well logs data quality is assessed and conditioned. We employed an inclusion-based rock physics model to estimate elastic (P-wave, S-wave, and density) properties by accounting for the effect of mineralogy using pore geometry (pore aspect ratio) variation. The RPM provided consistent elastic and petrophysical properties when compared with measured logs and improved lithofacies understanding in the tight gas reservoir. Finally, modeled elastic properties and lithofacies are assessed and characterized in a rock physics template (RPT) using an effective medium theory. The successful application of the integrated workflow exterminated the well log interpretation uncertainty by providing a consistency between the petrophysics and RPM, which can be extended for improved reservoir characterization and prospect evaluation across other areas with similar geological trends and reservoir distribution. [ABSTRACT FROM AUTHOR]

Carbonate rock is a critical reservoir for China's onshore oil and gas exploration. Carbonate reservoirs in different regions significantly differ in sedimentary and diagenesis processes and factors affecting their petrophysical and seismic rock physics properties. Therefore, it is critical to analyze the corresponding properties of carbonate rocks in different regions. Based on systematic petrological, rock microstructure, physical property, and seismic elastic characteristic measurements of deep carbonate reservoir samples in the Tarim Basin, the variation laws and influencing factors of the samples' physical and seismic elastic properties are analyzed. Based on these measurements, the variation patterns and influencing factors of petrophysical and seismic rock properties of rock samples are analyzed. The results show that the carbonate pore structure controls the overall variations of petrophysical and seismic rock physical properties of carbonate samples, and it is challenging to build a simple statistical model of porosity—permeability, porosity—velocity, and density—velocity. P- and S-velocities correlate well, and the P-and S-velocity ratio is a good index for rock typing. For tight carbonate samples, apparent velocity dispersion at a seismic exploration frequency band (5–200 Hz) can be observed, and the pore structure controls the velocity dispersion and attenuation features. Carbonate samples with crack-dissolution pores show moderately stronger velocity dispersion than samples with dissolution and microcrack pores. The pore aspect ratio and the frame flexibility factor (γ) calculated from the seismic rock physics model correlate well with pore structure parameters, such as the characteristic ratio surface. The pore aspect ratio and frame flexibility factor can be used to quantitatively characterize the changes in the pore structure of tight carbonate samples, reflecting the pore structure effects on the elastic wave velocity. This study's results can provide a basis for rock-typing carbonate reservoirs, lithology, and hydrocarbon detection of relevant reservoirs. [ABSTRACT FROM AUTHOR]