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Molecular dynamics simulations have been widely used in exploring the nucleation behavior of many systems, including gas hydrates. Gas hydrates are ice-like solids in which gas molecules are trapped in water cages. During hydrate formation, a considerable amount of heat is released, and previous work has reported that the choice of temperature control scheme may affect the behavior of hydrate formation. The origins of this effect have remained an open question. To address this question, extensive NVE simulations and thermostatted (NPT and NVT) simulations with different temperature coupling strengths have been performed and compared for systems where a water nanodroplet is immersed in a H2S liquid. Detailed analysis of the hydrate structures and their mechanisms of formation has been carried out. Slower nucleation rates in NVE simulations in comparison to NPT simulations have been observed in agreement with previous studies. Probability distributions for various temperature measures along with their spatial distributions have been examined. Interestingly, a comparison of these temperature distributions reveals a small yet noticeable difference in the widths of the distributions for water. The somewhat reduced fluctuations in the temperature for the water species in the NVE simulations appear to be responsible for reducing the hydrate nucleation rate. We further conjecture that the NVE-impeded nucleation rate may be the result of the finite size of the surroundings (here the liquid H2S portion of the system). Additionally, a local spatial temperature gradient arising from the heat released during hydrate formation could not be detected. [ABSTRACT FROM AUTHOR]

This paper focuses on phase and aggregation behavior for linear chains composed of blocks of hydrophilic and hydrophobic segments. Phase and conformational transitions of patterned chains are relevant for understanding liquid–liquid separation of biomolecular condensates, which play a prominent role in cellular biophysics and for surfactant and polymer applications. Previous studies of simple models for multiblock chains have shown that, depending on the sequence pattern and chain length, such systems can fall into one of two categories: displaying either phase separation or aggregation into finite-size clusters. The key new result of this paper is that both formation of finite-size aggregates and phase separation can be observed for certain chain architectures at appropriate conditions of temperature and concentration. For such systems, a bulk dense liquid condenses from a dilute phase that already contains multi-chain finite-size aggregates. The computational approach used in this study involves several distinct steps using histogram-reweighting grand canonical Monte Carlo simulations, which are described in some level of detail. [ABSTRACT FROM AUTHOR]

Reservoir in-situ stress is crucial in oil and gas exploration and development. With the transitional shale as the research object, the ultrasonic transmission test and uniaxial compression test of rock samples from different sampling angles were performed. Further, the transversely isotropic in-situ stress logging calculation method for transitional shale reservoirs was established based on the transversely isotropic constitutive relationship. Finally, the in-situ stress profile of the transitional shale reservoir in the study area was analyzed, and the reliability of the results was verified. The results indicated that the mechanical characteristics of rock and its acoustic velocity varied significantly depending on the sample angle, with some regularity in the changes between vertical and horizontal mechanical properties. The logging profile revealed that the transverse Young modulus was greater than the vertical, and the vertical Poisson's ratio was typically greater than the transverse. The suggested transversely isotropic model performed better than the conventional in-situ stress model at predicting the in-situ stress of transitional shale reservoirs, with an error of less than 2%. This demonstrated the applicability of the model's in-situ stress calculation of the transitional shale reservoir. [ABSTRACT FROM AUTHOR]

Gas–solid Fluidized bed technology has a pivotal role in coal separation. Bubble movement behavior is an important factor affecting the fluidization stability. Fluidized bed measurement is an essential link in the bubble behavior study. As the main evaluation parameters, the concentration distribution and density distribution can reflect the bubble movement behavior. This work uses a noninvasive method of electrical capacitance tomography (ECT) for fluidized bed measurements, combined with COMSOL simulation validation for real-time imaging of bubbles in Geldart Group B magnetite powder particles. Meanwhile, the most suitable reconstruction algorithm for gas–solid separation fluidized bed is selected from three image reconstruction algorithms. And then concentration distribution and density distribution are analyzed. The results show that under reasonable gas velocity conditions (U–Umf =2.28 and 3.17 cm/s), the central region ([0, 1/4]) concentrations of [0.43–0.45] and [0.39–0.42] and densities of [1.98–2.06 g/cm3] and [1.86–1.96 g/cm3] are obtained by ECT measurements, respectively. Finally, the bed density obtained from the ECT sensors in the experiment was validated using three different bed density models. The error can be controlled to within 20%, which indicates that the ECT measurement method has a fairly high reliability and accuracy in dry coal beneficiation field. [ABSTRACT FROM AUTHOR]

Fractured hydrate-bearing reservoirs are extensively discovered worldwide and show notable anisotropic geophysical properties. Hydrate distribution in fractures significantly affects the anisotropic properties, and hence plays an important role in the accurate assessment of hydrate resources. However, the knowledge about how the hydrate distribution impacts the anisotropic geophysical properties of fractured reservoirs, which is the premise for the identification and quantification of hydrate in fractured reservoirs, is still poorly understood. To obtain such knowledge, we forward study the effects of various hydrate distribution (including floating, bridging and evolving hydrate distribution) in aligned fractures on the anisotropic elastic, electrical and joint elastic–electrical properties of a digital core using validated numerical methods. We show that for all the hydrate distribution, the anisotropic velocities increase, while the conductivities decrease with increasing hydrate saturation, with the effects of the floating and bridging distribution being the least and greatest, respectively. We also show that the anisotropic velocities and conductivities for the floating and bridging distribution vary approximately linearly with hydrate saturation, leading to linear correlations between the elastic and electrical properties. Further investigation illustrates that the difference in the slopes of the linear joint correlations between the two distribution is significantly greater than that of the individual properties as a function of hydrate saturation. The results have revealed the distinct effects of hydrate distribution on the anisotropic elastic and electrical properties of fractured reservoirs, and have confirmed the superiority of the joint elastic–electrical properties for the distinguishment of hydrate distribution in fractures over individual physical properties. [ABSTRACT FROM AUTHOR]

Combining elastic full waveform inversion (FWI) with rock physics holds promise for expanding the application of FWI beyond seismic imaging to predicting and monitoring reservoir properties. Distributed acoustic sensing (DAS), a rapidly developing seismic acquisition technology, is being explored for its potential in supporting FWI applications. In this study, we implement a sequential inversion scheme that integrates elastic FWI and Bayesian rock physics inversion, using a vertical seismic profile (VSP) data set acquired with accelerometer and collocated DAS fibre at the Carbon Management Canada's Newell County Facility. Our aim is to establish a baseline model of porosity and lithology parameters to support later monitoring of CO2 storage. Key strategies include an effective source approach for addressing near-surface complications, a modelling strategy to simulate DAS data comparable to field data, and a Gaussian mixture approach to capture the bimodality of rock properties. We conduct FWI tests on accelerometer, DAS, and combined accelerometer-DAS data. While our inversion results accurately reproduce either data set, the elastic models inverted from accelerometer data outperform the other two in matching well logs and identifying the target reservoir. We attribute this outcome to the limited complementarity of DAS data with accelerometer data in our experiment, along with the limitations imposed by single-component measurements on DAS. The porosity and lithology models predicted from accelerometer-derived elastic models are reasonably accurate at the well location and exhibit geologically meaningful spatial distribution. [ABSTRACT FROM AUTHOR]

• A fully coupled three-dimensional THMC model (DEHydrate) is developed for simulating hydrate dissociation. • The numerical results obtained from the proposed model are in good agreement with those from other simulations. • Only a small fraction of gas produced from radial hydrate dissociation is collected from the wellbore. • The model provides an effective tool to predict the mechanical behavior during hydrate dissociation. Due to high energy density and huge reserves, many trial projects worldwide have been conducted to exploit natural gas hydrates (NGH). However, most of them did not meet the commercialization requirements because of submarine hazards, low gas production and sand production. Therefore, it is important to investigate the NGH dissociation process. In this paper, a fully coupled multiphase, strongly nonlinear three-dimensional (3D) thermal–hydro–mechanical–chemical model (DEHydrate) is developed to consider the multiphysics behaviours including solid-liquid-gas multiphase flow, heat transfer, NGH phase transition and solid deformation during hydrate dissociation. The model is solved using a fully implicit finite element method. The gas-liquid flow and heat transfer are simulated by low-order elements while the solid deformation is calculated by high- or low-order elements. The behaviours of the multiphase seepage and geomechanics are fully coupled and the physical properties of the reservoir are updated iteratively based on changes in pressure, temperature and displacement. The DEHydrate simulator provides an effective tool to predict the evolution of reservoir mechanical behavior during hydrate dissociation, including transient pressure, temperature, displacement and stress in the reservoir, as well as multiphase saturation, hydrate dissociation rate/mass and gas production rate/mass. During the NGH dissociation, the initial stage exhibits a rapid dissociation rate of up to 206.23 kg/(d·m) for NGH layer with a length of 600 m and a thickness of 22 m, which subsequently decreases to 11.64 kg/(d·m). Only a small portion of the gas generated during NGH dissociation is collected at the wellbore (approximately 35.6 % after 100 days), while the majority remains trapped in the reservoir. In addition, throughout NGH dissociation, the reservoir matrix continues to move toward the wellbore in the horizontal direction. While in the vertical direction, the reservoir matrix below the wellbore moves upwards, with decreasing displacement due to low-pressure diffusion, while the reservoir matrix above the wellbore moves downwards, with increasing displacement. The largest displacements occur near the wellbore during the early stage of NGH dissociation, while in the late stage, the largest displacements occur above the reservoir. [ABSTRACT FROM AUTHOR]

The pore-fracture structure of deep coal reservoirs is highly important for evaluating, exploring, and developing coalbed methane (CBM) resources. This study considers three coal samples from the DJ57 well in the Benxi Formation in the Daning–Jixian block on the eastern margin of the Ordos Basin as the research object. Based on the coal quality parameters of the coal samples, field emission scanning electron microscopy (FE-SEM), gas adsorption experiments, high-pressure mercury intrusion porosimetry (MIP), and microcomputed tomography (micro-CT) scanning were used to quantitatively characterize the nanoscale pores and microscale fractures in deep coal reservoirs and to evaluate the pore-fracture structure at different scales. The results reveal that the pore types in the Benxi Formation coal samples are diverse and include mainly organic matter (OM) pores, inorganic pores (intraparticle and interparticle pores), and microfractures. The organic pores are diverse in shape and mainly exhibit round, oval, and wedge shapes, while the microfractures exhibit slender stripes or serrated curves. The multiscale quantitative characterization of deep coal reservoir pores and fractures is based on a variety of pore characterization methods, and the pore and fracture volume distributions are mainly U-shaped, revealing the coexistence of micropores and microfractures. The volumes of micropores (0.3–2 nm), mesopores (2–50 nm), macropores (50 nm to 10 μm), and microfractures (>10 μm) account for 78.00%, 6.78%, 2.08%, and 13.14%, respectively, of the total pore volume (PV). Based on a full-scale pore-fracture splicing calculation, the total permeability of the Benxi Formation coal samples ranges from 5.77 to 28.22 mD. The observation results indicate that the microfractures are connected to each other, forming a network structure with strong connectivity. The microfractures are mainly associated with pore diameters > 100 μm, accounting for approximately 95% of the total permeability. Moreover, micropores in deep coal reservoirs provide a large space for CBM adsorption, and microfractures enhance the seepage capacity of CBM. [ABSTRACT FROM AUTHOR]

Gas condensate reservoirs are generally a mixed system of hydrocarbon and water. This paper is aimed to investigate the phase behavior change influenced by water vapor during the development of depletion and CO2 injection. The Gnorth reservoir of Zhanazhol oilfield in Caspian Basin is taken as an example. Two-phase flash was based on QNSS\Newton method, and multiple contact calculations were performed through cell-to-cell method. The research results indicate that, for the remaining reservoir fluid of depletion development, water vapor has the largest effect on the content change of CH4, followed by C7+, and the smallest effect on C2 to C6. The presence of water vapor makes it easier for the condensate to drop out of the gas phase. For CO2 injection, water vapor is not beneficial to re-evaporation for the formation condensate. Further, the multiple contact miscibility of CO2 and condensate is less affected by water vapor. [ABSTRACT FROM AUTHOR]

A key point for the development of a renewable energy economy at a large scale is the possibility to use the current natural gas network and storage capacity to transport and store hydrogen. This study is dedicated to evaluate the integrity of materials used for underground aquifer storage regarding hydrogen embrittlement in a gaseous environment saturated with water vapour and containing few amounts of H 2 S. In this environment, the water vapour content in the gas stored may reach saturation at bottom well pressure and temperature. It is known that the presence of impurities in the gas, such as H 2 O, can promote or inhibit hydrogen embrittlement phenomenon, depending on the nature of the steel. This work investigates mechanical properties of a tempered martensite N80-Q steel, and a ferrite-perlite L360-NB C–Mn steel issued from a completion and a collect tube respectively. The testing environments are NG, NG + H 2 S, NG + 25%H 2 and NG + 25%H 2 + H 2 S saturated in water vapour at 8.5 MPa and room temperature. These environmental conditions aim at replicating the storage service conditions. Fracture toughness and fatigue crack growth properties are assessed. So far, the mechanical behaviour of such steels under hydrogen gas pressure saturated with water vapour and low amount of H 2 S has poorly been addressed. Regarding toughness properties, the two steels present different behaviour: for the L360 NB crack has not propagated for any testing environments, while cracks propagated in all the tests for the N80 Q. Despite this difference, for the two steels, the toughness does not seem to be affected by hydrogen as the results obtained in NG + 25%H 2 + H 2 O and NG + H 2 O are similar. Based on the literature C–Mn steels toughness is affected by the presence of dry hydrogen. Hence, the results presented here show that H 2 O inhibits hydrogen embrittlement as far as toughness is concerned. The L360NB, however, presented a slight decrease in toughness properties with the combination of NG + 25%H 2 + H 2 S + H 2 O. FCG (fatigue crack growth) results, on the opposite, clearly highlight the influence of hydrogen on the mechanical behaviour of the two steels. The FCG rates are faster from a factor five (resp. 10) in NG + 25%H 2 + H 2 O compared to NG + H 2 O for the N80 Q (resp. L360). In this article, toughness and FGC results on the two steels are discussed in terms of microstructure and mechanical loading modes, aiming to quantify and better understand the influence of H 2 O and H 2 S on the sensitivity of low alloy steels to hydrogen embrittlement. • The hydrogen embrittlement of metallic components used for underground hydrogen storage is studied. • The fracture toughness and fatigue crack growth properties in 8.5 MPa H 2 are discussed. • The effect of a gas saturated with water vapour and/or containing small amount of H 2 S is studied. • Water vapour mitigates hydrogen deleterious effect on fracture toughness of the two studied steels (ferritic and martensitic). • A synergetic hydrogen embrittlement effect between water vapour and H 2 S is highlighted. [ABSTRACT FROM AUTHOR]

The Bozhong19-6 (BZ19-6) condensate gas reservoirs, located in the southwestern Bozhong sub-basin, Bohai Bay Basin, China, were paleo-oil reservoirs in the geological past and have undergone at least three successive hydrocarbon charging events. The hydrocarbon migration and accumulation process of "early oil and late gas" has occurred in the current reservoirs. At the end of the sedimentation of the Guantao Formation (N1g, ∼12 Ma), the reservoirs began to fill with first stage low-moderate mature crude oil. At the late stage of the Lower Minghuazhen Formation (N1ml) (∼6.7 Ma), the reservoirs were largely charged with second stage high mature crude oil. Since the deposition of the upper Minghuazhen Formation (N2mu, ∼5.1 Ma), the paleo-oil reservoirs were transformed into shallow Neogene reservoirs due to the reactivation of basement faults. From the late stage of the N2mu to the present day (∼2.8–0 Ma), the reservoirs were rapidly filled by natural gas within a short period. In addition, analysis of the formation of the reservoir bitumen and the conspicuous loss of the lower molecular weight n-alkanes in the crude oil reveal that the injection of a large amount of gas in the late stage caused gas flushing of the early charged oil. [ABSTRACT FROM AUTHOR]

The tight tuff reservoir is an unusual type of unconventional reservoir with strong heterogeneity. However, there is a lack of research on the microscopic pore structure that causes the heterogeneity of tuff reservoirs. Using the Chang 7 Formation in Ordos Basin, China as a case study, carbon-dioxide gas adsorption, nitrogen gas adsorption and high-pressure mercury injection are integrated to investigate the multi-scale pore structure characteristics of tuff reservoirs. Meanwhile, the fractal dimension is introduced to characterize the complexity of pore structure in tuff reservoirs. By this multi-experimental method, the quantitative characterizations of the full-range pore size distribution of four tuff types were obtained and compared in the size ranges of micropores, mesopores and macropores. Fractal dimension curves derived from full-range pores are divided into six segments as D1, D2, D3, D4, D5 and D6 corresponding to fractal characteristics of micropores, smaller mesopores, larger mesopores, smaller macropores, medium macropores and larger macropores, respectively. The macropore volume, average macropore radius and fractal dimension D5 significantly control petrophysical properties. The larger macropore volume, average macropore radius and D5 correspond to favorable pore structure and good reservoir quality, which provides new indexes for the tuff reservoir evaluation. This study enriches the understanding of the heterogeneity of pore structures and contributes to unconventional oil and gas exploration and development. [ABSTRACT FROM AUTHOR]

Due to the complex conditions and strong heterogeneity of tight sandstone reservoirs, the reservoirs should be classified and the controlling factors of physical properties should be studied. Cast thin section observations, cathodoluminescence, scanning electron microscopy (SEM), X-ray diffraction (XRD), and high-pressure mercury injection (HPMI) were used to classify and optimize the reservoir. The Brooks-Corey model and stepwise regression were used to study the fractal dimension and main controlling factors of the physical properties of the high-quality reservoir. The results show that the reservoirs in the study area can be divided into four types, and the high-quality reservoir has the best physical properties and pore-throat characteristics. In the high-quality reservoir, the homogeneity of transitional pores was the best, followed by that of micropores, and the worst was mesopores. The porosity was controlled by depth and kaolinite. The model with standardized coefficients is y = 12.454 − 0.778 × (Depth) + 0.395 × (Kaolinite). The permeability was controlled by depth, illite/montmorillonite, and siliceous cement, and the model with standardized coefficients is y = 1.689 − 0.683 × (Depth) − 0.395 × (Illite/Montmorillonite) − 0.337 × (Siliceous Cement). The pore-throat evolutionary model shows that the early-middle diagenetic period was when the reservoir physical properties were at their best, and the kaolinite intercrystalline pores and residual intergranular pores were the most important. [ABSTRACT FROM AUTHOR]

The phase behavior of gas condensate in reservoir formations differs from that in pressureevolume etemperature (PVT) cells because it is influenced by porous media in the reservoir formations. Sandstone was used as a sample to investigate the influence of porous media on the phase behavior of the gas condensate. The pore structure was first analyzed using computed tomography (CT) scanning, digital core technology, and a pore network model. The sandstone core sample was then saturated with gas condensate for the pressure depletion experiment. After each pressure-depletion state was stable, realtime CT scanning was performed on the sample. The scanning results of the sample were reconstructed into three-dimensional grayscale images, and the gas condensate and condensate liquid were segmented based on gray value discrepancy to dynamically characterize the phase behavior of the gas condensate in porous media. Pore network models of the condensate liquid ganglia under different pressures were built to calculate the characteristic parameters, including the average radius, coordination number, and tortuosity, and to analyze the changing mechanism caused by the phase behavior change of the gas condensate. Four types of condensate liquid (clustered, branched, membranous, and droplet ganglia) were then classified by shape factor and Euler number to investigate their morphological changes dynamically and elaborately. The results show that the dew point pressure of the gas condensate in porous media is 12.7 MPa, which is 0.7 MPa higher than 12.0 MPa in PVT cells. The average radius, volume, and coordination number of the condensate liquid ganglia increased when the system pressure was between the dew point pressure (12.7 MPa) and the pressure for the maximum liquid dropout, Pmax (10.0 MPa), and decreased when it was below Pmax. The volume proportion of clustered ganglia was the highest, followed by branched, membranous, and droplet ganglia. This study provides crucial experimental evidence for the phase behavior changing process of gas condensate in porous media during the depletion production of gas condensate reservoirs. [ABSTRACT FROM AUTHOR]

This article examines the efficiency of gas condensate heaters in the context of reducing the operating costs of combined-cycle gas installations. Gas condensate heaters are an innovative technological solution aimed at restoring the heat released during steam condensation. Based on the principles of returning part of the heat back to the system, their use contributes to a significant reduction in fuel consumption, which, in turn, leads to a reduction in operating costs. The work examines the mechanisms of operation of gas condensate heaters, their thermal characteristics, as well as their impact on the overall energy efficiency of combined-cycle gas installations. Using the example of the oil refining industry, the practical application of this technology for optimizing thermal processes is demonstrated. In conclusion, the importance of gas condensate heaters in the context of building environmentally sustainable and energy-efficient production systems is emphasized. [ABSTRACT FROM AUTHOR]

Fractures are common features in deep gas reservoirs with strong heterogeneity, which are generally evaluated by well-testing analysis. Based on the characteristics of a variety of spatial scales from microscopic fractures to macroscopic faults in the Kuche area, this paper investigated the pressure behavior of naturally fractured gas reservoirs by using four typical patterns, including the Warren–Root model, radial composite model, dual-flow-state model, and local heterogeneity model. As a result, typical well-testing curves and parameter sensitivity analysis were demonstrated in detail. Furthermore, the pressure transient behavior of multi-scaled fractured reservoirs was identified by use of a state-of-the-art workflow. The analysis shows that the four patterns and their identification processes were feasible for the inversion of reservoir parameters in fractured gas reservoirs. Combined with dynamic data, the proposed method could further guide the optimization of development schemes and is of great significance for the development of fractured gas reservoirs. [ABSTRACT FROM AUTHOR]

In the process of coalbed methane development, drilling fluid and fracturing fluid cannot achieve absolute compatibility with formation. The incompatibility between the working fluid and reservoir will lead to the intrusion of working fluid into the reservoir and cause reservoir pollution. This is a very common phenomenon. There is a large amount of pulverized coal in the coal seam, and the intrusion of working liquid will be combined with the pulverized coal to form cement to block the seepage space in the reservoir. Since pressure relief and fracturing fluid backflow will be performed at the first time after fracturing, the intrusion range of the working fluid is small, generally reaching 10 m to 50 m. Compared with a conventional gas reservoir or shale gas reservoir, the working fluid loss during CBM development will seriously affect the subsequent production project and even make the gas well lose production capacity. On the other hand, in order to avoid this phenomenon, measures such as acidification or volumetric fracturing are sometimes used to improve the seepage environment near the well and near the fracture. The purpose of this study is to quantitatively evaluate the impacts of working fluid filtration and reservoir reconstruction on production. In this study, a single well productivity evaluation model and sensitivity analysis method considering drilling fluid filtration loss, fracturing fluid filtration loss, reservoir reconstruction and other processes is proposed. The formation mechanism of fluid loss during drilling and fracturing is described, and the productivity evaluation model considering fluid loss is combined with the Langmuir isothermal adsorption equation, steady-state diffusion law, Darcy's seepage law and Duhamel convolution formation. Combined with the distribution of actual gas reservoir flow characteristics, the sensitivity of single well productivity to gas reservoir porosity, gas reservoir permeability, coal seam adsorption coefficient, working fluid filtration loss and reservoir reconstruction measures are analyzed. Through the analysis and fitting of the actual production data on site, the relationship curve can better fit the field production data, and the evaluation results are in line with the drilling and fracturing conditions at that time and the subsequent production conditions, with small errors. The obtained method is suitable for predicting the productivity of fractured vertical wells in different working conditions and provides a basis for the development and productivity prediction of CBM reservoirs in China and in international cooperation. [ABSTRACT FROM AUTHOR]

This investigation ventures into the nuanced porosity traits of shallow shale gas reservoirs, pinpointing the critical determinants of their gas content with a nuanced touch. By harnessing sophisticated microscopy and analytical methods, we embarked on an exploration into the porosity architecture of shale, identifying the distinct pore spaces that harbor shale gas and applying gas adsorption techniques to evaluate its storage potential. Noteworthy is our utilization of diverse adsorption mechanisms and models to accurately fit methane adsorption data while carefully considering the influence of marine shallow shale's pore structure peculiarities, total organic carbon (TOC) content, and clay mineral content on its adsorption prowess. We introduce a refined model for appraising gas adsorption volumes, an innovative stride toward bolstering the precise estimation of reserves in marine dam shallow shale gas and shedding light on accurate gas adsorption volume calculations in analogous shallow shale gas scenarios. This manuscript offers profound insights into the sophisticated interplay between shale porosity and gas storage, enriching our understanding and enabling more accurate future resource estimations. [ABSTRACT FROM AUTHOR]

Conventional recovery enhancement techniques are aimed at reducing the abandonment pressure, but there is an upper limit for recovery enhancement due to the energy limitation of reservoirs. Gas injection for energy supplementation has become an effective way to enhance gas recovery by reducing hydrocarbon saturation in gas reservoirs. This review systematically investigates progress in gas injection for enhanced gas recovery in three aspects: experiments, numerical simulations and field examples. It summarizes and analyzes the current research results on gas injection for EGR and explores further prospects for future research. The research results show the following: (1) Based on the differences in the physical properties of CO2, N2 and natural gas, effective cushion gas can be formed in bottom reservoirs after gas injection to achieve the effects of pressurization, energy replenishment and gravity differentiation water resistance. However, further experimental evaluation is needed for the degree of increase in penetration ability. (2) It is more beneficial to inject N2 before CO2 or the mixture of N2 and CO2 in terms of EGR effect and cost. (3) According to numerical simulation studies, water drive and condensate gas reservoirs exhibit significant recovery effects, while CO2-EGR in depleted gas reservoirs is more advantageous for burial and storage; current numerical simulations only focus on mobility mass and saturation changes and lack a mixed-phase percolation model, which leads to insufficient analysis of injection strategies and a lack of distinction among different gas extraction effects. Therefore, a mixed-phase-driven percolation model that can characterize the fluid flow path is worth studying in depth. (4) The De Wijk and Budafa Szinfelleti projects have shown that gas injection into water drive and depleted reservoirs has a large advantage for EGR, as it can enhance recovery by more than 10%. More experiments, simulation studies and demonstration projects are needed to promote the development of gas injection technology for enhanced recovery in the future. [ABSTRACT FROM AUTHOR]

The oral mucosa represents a defensive barrier between the external environment and the rest of the body. Oral mucosal cells are constantly bathed in hypotonic saliva (normally one-third tonicity compared to plasma) and are repeatedly exposed to environmental stresses of tonicity, temperature, and pH by the drinks we imbibe (e.g., hypotonic: water, tea, and coffee; hypertonic: assorted fruit juices, and red wines). In the mouth, the broad-spectrum antiviral mediator MxA (a dynamin-family large GTPase) is constitutively expressed in healthy periodontal tissues and induced by Type III interferons (e.g., IFN-λ1/IL-29). Endogenously induced human MxA and exogenously expressed human GFP-MxA formed membraneless biomolecular condensates in the cytoplasm of oral carcinoma cells (OECM1 cell line). These condensates likely represent storage granules in equilibrium with antivirally active dispersed MxA. Remarkably, cytoplasmic MxA condensates were exquisitely sensitive sensors of hypotonicity—the condensates in oral epithelium disassembled within 1–2 min of exposure of cells to saliva-like one-third hypotonicity, and spontaneously reassembled in the next 4–7 min. Water, tea, and coffee enhanced this disassembly. Fluorescence changes in OECM1 cells preloaded with calcein-AM (a reporter of cytosolic "macromolecular crowding") confirmed that this process involved macromolecular uncrowding and subsequent recrowding secondary to changes in cell volume. However, hypertonicity had little effect on MxA condensates. The spontaneous reassembly of GFP-MxA condensates in oral epithelial cells, even under continuous saliva-like hypotonicity, was slowed by the protein-phosphatase-inhibitor cyclosporin A (CsA) and by the K-channel-blocker tetraethylammonium chloride (TEA); this is suggestive of the involvement of the volume-sensitive WNK kinase-protein phosphatase (PTP)-K-Cl cotransporter (KCC) pathway in the regulated volume decrease (RVD) during condensate reassembly in oral cells. The present study identifies a novel subcellular consequence of hypotonic stress in oral epithelial cells, in terms of the rapid and dynamic changes in the structure of one class of phase-separated biomolecular condensates in the cytoplasm—the antiviral MxA condensates. More generally, the data raise the possibility that hypotonicity-driven stresses likely affect other intracellular functions involving liquid–liquid phase separation (LLPS) in cells of the oral mucosa. [ABSTRACT FROM AUTHOR]

The functional importance of nuclear protein condensation remains often unclear. The bHLH FER-like iron deficiency-induced transcription factor (FIT) controls iron acquisition and growth in plants. Previously described C-terminal serine residues allow FIT to interact and form active transcription factor complexes with subgroup Ib bHLH factors such as bHLH039. FIT has lower nuclear mobility than mutant FITmSS271AA. Here, we show that FIT undergoes a light-inducible subnuclear partitioning into FIT nuclear bodies (NBs). Using quantitative and qualitative microscopy-based approaches, we characterized FIT NBs as condensates that were reversible and likely formed by liquid-liquid phase separation. FIT accumulated preferentially in NBs versus nucleoplasm when engaged in protein complexes with itself and with bHLH039. FITmSS271AA, instead, localized to NBs with different dynamics. FIT colocalized with splicing and light signaling NB markers. The NB-inducing light conditions were linked with active FIT and elevated FIT target gene expression in roots. FIT condensation may affect nuclear mobility and be relevant for integrating environmental and Fe nutrition signals. [ABSTRACT FROM AUTHOR]

The permeability of shale controls gas transport in shale gas reservoirs. The shale has a complex pore structure at the nanoscale and its permeability is affected by multiple transport and action mechanisms. In this study, a 3D fractal model for predicting the apparent gas permeability of shale matrix is presented, accounting for the effects of the transport mechanisms (bulk gas transport and adsorption gas diffusion) and action mechanisms (gas adsorption, real gas properties, water film, stress dependence, and total organic carbon (TOC) content). The proposed model is validated with the published experimental data. A series of sensitivity analyses are performed to investigate the influence of fractal characteristics and action mechanisms on the apparent permeability caused by each transport mechanism. The results show that the real gas properties, water film, and stress dependence cause different effects on the total apparent permeability of shale under different fractal characteristics. The maximum pore diameter is inversely proportional to the effects of these action mechanisms, and the porosity is positively proportional to the effects of real gas properties and water film but inversely proportional to the effects of stress dependence. An increase in TOC content can cause an improvement in the total apparent permeability. Furthermore, the effects of action mechanisms on the apparent permeability caused by different transport mechanisms are differently affected by the fractal characteristics. Changes in fractal characteristics mainly affect the apparent permeability caused by slip flow in the real gas effect, slip flow and Knudsen diffusion in the water film effect, and all transport mechanisms in the stress dependence effect. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing (HF) often stimulates the local earthquake productivity which provides a unique opportunity to characterize the crustal heterogeneities, reservoir properties and fluid injection effects. However, the velocity models acquired solely based on the arrival time records are often undermined due to the seismic network coverage and interpolation techniques. Instead, we adopt the waveform-based approach to apprehend; (1) structural heterogeneities, (2) reservoir distribution and (3) signatures of the injected fluid in the Weiyuan shale gas field. We categorize the waveforms into dominant high and low frequencies based on the qualitative inspection and frequency index analysis of the seismic waveforms. We first inspect the waveform to access the potential controlling mechanisms (source, site and path effects) at both single and multiple stations in different azimuthal orientations. As a result, we find the path effect as a dominant factor to influence the waveform characteristics, for example S -wave amplitude, and frequency. Subsequently, to localize the path effect, we conduct an in-depth examination of events within 10 km of each seismic station and classify the waveform records using their frequency indices. Notably, certain stations record a significant proportion of low-frequency waveforms (LFWs, up to 20 per cent), while others have limited occurrences (∼1 per cent) indicating suspected anomalous zones. Afterward, we identify two suspected anomalous zones based on LFWs intensity and ray tracing map. Both zones are in close proximity to fault zones and preserved reservoirs with no HF activities, where fault damage zones or the fluid-rich reservoir may contribute to our observed LFWs. [ABSTRACT FROM AUTHOR]

Oil shale is a potential strategic resource with large reserves and widespread application potential, and in situ combustion is an effective method to exploit oil shale. However, the interaction mechanism between pyrolysis and combustion reaction is still not clear; hence, the evolution of components and temperature in the reservoir is hard to describe, limiting the application of in situ combustion in oil shale. In this paper, we established a comprehensive reactive flow model to describe the in situ combustion in oil shale, and the in situ combustion process is analyzed in detail. During the in situ combustion, only pyrolysis reactions occur in the matrix system, while combustion reactions only occur in the fracture system. Under the interaction mechanisms of these two kinds of chemical reactions, in situ combustion upgrading can be carried out continuously. The produced oil and hydrocarbon gas per unit volume of oil shale are 0.06 m3/m3 and 12.5 m3/m3 , respectively, but about 83.3 m3/m3 of CO2 is produced that needs to be stored subsequently when air is directly injected into the reservoir to maintain the combustion reactions. Increasing oil content and air injection rate can increase the cumulative oil and gas production, but there are optimal values above which the increase rate slows down. The energy conversion efficiency of in situ combustion is 49.5, and it is much higher than the energy conversion efficiency in other in situ upgrading methods for oil shale. [ABSTRACT FROM AUTHOR]

Underground hydrogen storage in porous media (UHSP), typically employing depleted natural gas reservoirs, is being increasingly contemplated as a potentially viable energy storage option to compensate for intermittent renewable energy sources. A layer of cushion gas (typically N 2 , CH 4 or CO 2) is proposed to be accommodated in such UHSP systems to allow for pressure and volume control during hydrogen (the so-called working gas) injection and withdrawal, while also serving as a barrier to prevent excess water contamination. One significant challenge in such UHSP systems is the potential mixing between this working gas (hydrogen) and the cushion gas within the relevant reservoir. Such mixing increases the risk of unacceptable extracted hydrogen contamination (with the cushion gas), often requiring expensive surface hydrogen purification processes. Therefore, the use of a cushion gas has potential economic implications. Accurate determination of the extent of this mixing requires reservoir simulations, which depend on dispersion coefficient (K L) data as input. Such data are however not available in the literature for hydrogen under relevant reservoir conditions. Here we present novel measurements of K L for the dispersion of hydrogen in the three prospective cushion gases as a function of system pressure (50–100 bar) and for displacement velocities ranging from 0.2 to 8.4 cm/min. • The dispersion coefficient (K L) between hydrogen and potential cushion gases was measured using a core flooding apparatus. • Measurements were executing using a Fontainebleau sandstone and N 2 , CH 4 and CO 2 as the potential cushion gases. • K L was obtained as a function of displacement velocity (0.2–8.4 cm/min) and system pressure (50–100 bar). • K L data for gaseous N 2 , CH 4 and CO 2 was scaled by the relevant diffusion coefficient, this was not the case for liquid CO 2. [ABSTRACT FROM AUTHOR]

Global demand for underground gas storage (UGS) is steadily increasing, with the limestone-based UGS system situated in the Sichuan Basin of China gathering considerable interest in recent years. However, studies focusing on the fundamental mechanisms of the injection-production process in these systems are limited. Moreover, existing studies utilizing physical experimental methods frequently fall short in effectively visualizing micro-flow or incorporating real core samples from the reservoir. To address these gaps, we performed a coreflood experiment, integrating micro-Computed Tomography (CT) scanning to investigate mechanisms of fluid flow and storage capacity during the injection and production cycles in limestone reservoirs. Our approach involved utilizing core plugs with artificially engraved fracture-vuggy structures, which mimic the characteristics of the reservoir. Micro-CT scans were performed to visualize the microscopic changes in fractured-vuggy structures and the distribution of irreducible water during each cycle. This study reveals that increased cycles correspondingly affect gas storage capacity, particularly by expanding it in relative larger vuggy structures while reducing it in finer fissure network structures. The amount of irreducible water decreases after injection-production cycles, likely being expelled alongside the extracted dry gas. This plays a critical role in expanding the storage capacity in larger vuggy systems. Conversely, there is a decrease in storage capacity within fissure network systems, as the irreducible water is replaced by gas. This leads to a reduction in the opening force of the fine conduit. The dense matrix has a very limited effect on the flow mechanism and its influence on storage capacity. Overall, these findings offer practical insights for optimizing injection and production strategies in limestone UGS systems within the Sichuan Basin, contributing to a deeper understanding and efficient utilization of this vital infrastructure. [ABSTRACT FROM AUTHOR]

The coupling relationship between the deformation field, the diffusion field, and the seepage field is an important factor in fluid transport mechanisms in the long-term coalbed methane (CBM) exploitation process. A mathematical model of gas–water two-phase fluid–structure coupling in a double-porosity medium in coal reservoirs is established in this paper. Taking Hancheng Block, a typical production block in Qinshui Basin, as the geological background critical desorption pressure, reservoir permeability anisotropy is considered in the model. COMSOL Multiphysics (COMSOL_6.0) was used to create the model. The accuracy and rationality of the model were verified by comparing field production data with the results of the simulation. Using the simulation, the influence law of various reservoir geological characteristics parameters (Langmuir strain constant, ratio of critical desorption pressure to reservoir pressure of coal seam (CDPRP), elastic modulus, initial water saturation, Langmuir pressure, etc.) on CBM productivity, reservoir pressure, and permeability ratio was discussed, and a thorough analysis of the factors affecting productivity was obtained using the orthogonal test method. The findings of this study indicate that the change in permeability is the result of the superposition effect of many factors. Different stages of drainage have different primary regulating factors. Rock skeleton stress has a consequence on coal matrix permeability in the early drainage stage, and coal matrix shrinkage is primarily impacted in the later drainage stage. Besides the initial water saturation, other reservoir geological parameters (e.g., CDPRP, Langmuir volume, Langmuir strain constant, elastic modulus) have a strong relationship with productivity. When the value of coal geological parameters increases, the degree of productivity release is higher (as the initial water saturation increases, the production decreases correspondingly). Different coal and rock parameters have varying levels of impact on the drainage stage of CBM wells. The influences of the CDPRP, Langmuir volume, Langmuir strain constant, and elastic modulus on gas production are mainly concentrated in the initial and intermediate drainage stages and begin to fall off during the last drainage stage. Per the multi-factor analysis, the main coal–rock parameters affecting the productivity release are the Langmuir strain constant, followed by the CDPRP and other parameters. The analysis findings can offer theoretical guidance for CBM well selection and layer selection and enhance the block's overall CBM development level. The improved productivity prediction model for CBM, which is based on fluid–structure coupling theory, can offer a new technical benchmark for CBM well productivity prediction. [ABSTRACT FROM AUTHOR]

As an important indicator for measuring the effectiveness and level of oil and gas field development, recovery rate has always been a focus in the research of oil and gas fields. Reservoirs of tight sandstone gas formations have significant characteristics of low porosity, high permeability, and high water content, which leads to greater difficulty in their development and makes it challenging to evaluate the recovery rate. Newtonian mechanics, as an important component of the mechanical system, is an innovative application of classical mechanics in the field of seepage mechanics when applied to the two-phase flow of gas and water. Firstly, starting from the perspective of mechanics analysis, we derive a steady-state model for gas–water two-phase infiltration and obtain the productivity equation based on this model. Then, according to the steady-state model, we establish a method to calculate the effective control radius of gas reservoirs under different production conditions and reservoir physical properties. Finally, using Matlab 2018a programming based on the productivity equation, we calculate the gas recovery under different conditions during constant pressure drop production and constant production rate production. The results indicate that the effective control radius of the reservoir decreases with an increase in the economic ultimate daily gas production, increases with an increase in production pressure difference, slightly decreases with an increase in startup pressure gradient, and correspondingly increases with an increase in microtube radius and quantity. Regardless of whether it is production with a fixed pressure drop or production with a fixed production rate, the gas recovery decreases as the production pressure drop and bottomhole abandonment pressure increase, but it increases as the proportion of the single-well control radius increases. In production with a fixed pressure drop, the gas recovery remains consistent across different reservoir quality indices. However, in production with a fixed production rate, the gas recovery initially increases rapidly and then gradually slows down as the reservoir quality index increases, and there is an obvious critical permeability (0.1 mD). The research findings are based on the mechanical analysis of porous media, delving into the laws governing fluid flow during infiltration. The derived infiltration model can be used to calculate the effective control radius and evaluate recovery rates, providing practical guidance for reservoir development. [ABSTRACT FROM AUTHOR]

Underground hydrogen storage (UHS) is gaining interest as a secure, long-term solution for storing hydrogen in porous geological formations. In UHS, a cushion gas like CO 2 is crucial to maintain the reservoir pressure and optimize recovery. The concept of wettability plays a fundamental role in determining the system's multi-phase displacement characteristics in the porous media. However, there is a gap in the existing literature regarding the wettability of sandstone rocks under geo-storage conditions when H 2 and CO 2 are injected as the bulk and cushion gases, respectively. To address this gap, we conducted a study investigating the wettability hysteresis phenomenon by measuring the advancing and receding contact angles of different mixtures of H 2 /CO 2 in contact with brine on a sandstone mineral under different pressures and temperatures, using the tilted plate method. The results show that the contact angle increases with pressure, leading the system to become less water-wet. Conversely, an increase in temperature makes the system more water-wet. Moreover, the measured contact angle remains relatively constant despite changes in the CO 2 concentration. Further analyses utilizing atomic force microscope (AFM) and energy dispersive X-ray spectroscopy (EDS) indicated that the chemical and physical structure of the rock does not change after exposure to CO 2 , consistent with the observed lack of wettability change with varying CO 2 fraction. In conclusion, the water-wet state identified under reservoir conditions decreases residual trapping of H 2 , facilitating higher recovery but posing a potential risk of leakage. Hence, using a higher fraction of CO 2 as a cushion gas is favorable for reducing the risk by decreasing IFT and, subsequently, the gas column. This study improves our understanding of hydrogen geo-storage mechanisms, aiding more accurate simulations in underground porous systems. • Rock wettability is crucial for UHS optimization. • Pressure reduces water-wettability, while higher temperatures enhance it. • CO 2 minimally alters rock wettability, making it favorable in H 2 storage. [ABSTRACT FROM AUTHOR]

Phase envelopes are routinely employed by reservoir engineers for fluid characterisation. These envelopes are controlled by reservoir fluid composition, pressure and temperature. As a result of increasing source-rock maturation, fluids with decreasing molecular weights and densities and increasing gas-to-oil ratios (and hence different phase envelopes) are generated, which are thus linked to fluid history. In addition to their importance for exploration, charge models can play a key role in constraining reservoir models and optimising field development, particularly when pressure–volume-temperature (PVT) data are properly integrated with fluid geochemistry. Two contrasting scenarios of fluid phase evolution from two different fields are presented, and their relations to charge analysis and reservoir models are discussed. The first example discusses the identification, based on hydrocarbon geochemistry complemented by overlapping modeled phase envelopes, of compartmentalised filling cycles in what was initially considered a single oil-rimmed gas accumulation. The second example presents an opposite scenario where two wet gas accumulations 20-km apart laterally and 400-feet average depth difference appear to represent a single more-expansive accumulation spread over areas of variable PVT conditions and reservoir qualities. The wet gas across both accumulations is characterised by a continuous phase evolution pattern that shrinks systematically (cricondentherm shifts to lower temperature and cricondenbar to lower pressure), suggestive of phase fractionation of a charge of single maturity. The proposed gas distribution model represents a discovery of a hybrid conventional and unconventional (tight sand) system, with potential for basin-centered gas. These findings provided better understanding of observed and projected fluids, impacting the development and completion plans by locating new gas producers. A recent well drilled midway between the two accumulations indeed tested wet gas, confirming fluid connectivity. Future work will attempt to link the gas distribution model with seismic attributes. [ABSTRACT FROM AUTHOR]

Geological storage of hydrogen, and its retrieval as needed, could play a vital role in the transition from fossil-fuel based energy to clean renewable energy production. Cushion gases, such as carbon dioxide and methane, can be used to maintain the reservoir pressure required to increase the efficiency of injection and extraction processes. Because water is ubiquitous in the subsurface, it can provide additional sealing mechanisms and affect the ability of gases to penetrate porous rocks. Because the interactions among the various gases and the wetting properties in the subsurface affect the sealing capacity of the caprock, they can provide important considerations for the proper design of geological storage and retrieval processes. Molecular dynamics simulations were used to evaluate the effects of varying compositions of cushion gases (CO 2 and CH 4) on brine-hydrogen-kaolinite clay wettability. Contact angles and liquid–gas interfacial tension were computed for 10% NaCl brines at 323 K and pressures in the range 5–40 MPa. These conditions are representative of underground gas storage. The results showed that, in pure H 2 , the kaolinite siloxane surface is 'intermediate wet', with contact angles ranging from 91° to 106°. At constant temperature and pressure, CO 2 and CH 4 cause the surface to become less water-wet, yielding larger contact angles. We observed that CO 2 led to a more significant increase in contact angles. This suggests that CO 2 or CH 4 lead to easier recovery of hydrogen. These cushion gases also reduce gas-brine interfacial tensions, with CH 4 yielding a less pronounced effect than CO 2. Reductions in interfacial tension translate to reduced capillary sealing pressure, which implies that hydrogen can be retrieved at lower pressures. The results presented suggest that the efficiency of a gas used as cushion gas is related to the density difference between the resultant gas mixture and water. At the conditions tested here, CO 2 and CH 4 are found to reduce the sealing capacity of kaolinite towards hydrogen storage, while they are likely to improve hydrogen recovery. This should be taken into consideration when intermittent hydrogen storage is attempted in geological repositories. Molecular dynamics simulations show: • In pure H 2 , the kaolinite siloxane surface presented contact angles for NaCl brine ranging from 91° to 106°. • The presence of CO 2 and CH 4 in H 2 /brine/kaolinite systems reduced the water wettability of kaolinite. • Both CH 4 and CO 2 reduced the brine-gas interfacial tension. • At all pressures, CO 2 had a more significant effect than CH 4 on both wettability and interfacial tension. • CO 2 and CH 4 reduce the sealing capacity of kaolinite, while they improve hydrogen recovery. [ABSTRACT FROM AUTHOR]

The Urho Formation in the Lower Permian System at the Junggar Basin in China commonly develops zeolite cements. The presence of zeolite minerals in various states of occurrence and uneven distribution in glutenite reservoirs makes it indeterminate to interpret the well logging response characteristics such as acoustic, resistivity, radioactivity, and nuclear magnetic resonance (NMR). This poses significant challenges for the evaluation of well loggings in glutenite reservoirs containing laumontite and the determination of oil and gas reserves. In this study, through petrophysics experiments such as whole-rock X-ray diffraction, conventional petrophysical properties, mercury injection, and electron microprobe analysis, the characteristics of glutenite reservoirs containing laumontite and the well logging response mechanisms were analyzed from the perspectives of mineral composition of rocks, geochemical characteristics, and principle of loggings. A multimineral optimization method was used to calculate the laumontite content. The results indicate that in the study area, the cementation of zeolite minerals dominated by laumontite suppresses the pore development in the reservoir, which is a crucial factor in the formation of complex pore structures and low-porosity low-permeability reservoirs. Since laumontite exhibits a water-bearing framework structure with numerous micropores and crystal water, the laumontite-bearing glutenite reservoirs are characterized by low natural gamma radiation, low density, high neutron porosity, and high electrical resistivity. The acoustic interval transit time shows no significant differences, while the NMR T 2 spectrum exhibits a short relaxation time. [ABSTRACT FROM AUTHOR]

The late-stage development of gas reservoirs often encounters the paradox of significant remaining formation pressure coupled with low wellhead pressure, which indicates small drainage volume, low gas production rate, and low recovery efficiency, reducing gas supply and economic benefit. Owing to the lack of experimental research, the reasons behind this contradiction between gas production and producing pressure differential are unclear. The key factors affecting the development outcomes are reservoir permeability and initial water saturation, while the evaluation parameters include gas and water production rates, reservoir pressure, and recovery efficiency. Based on the characteristic properties of typical gas fields, physical simulation experiments of constant-rate gas production are conducted on spliced long cores with average permeabilities of 2.300, 0.486, and 0.046 millidarcy (mD). Furthermore, leveraging the multi-point embedded pressure measurement technique, the pressure drawdown propagations and the macroscopic and microscopic characteristics of connate water production at the initial water saturations of 0%, 20%, 40%, and 55% are investigated. By connate water, we mean water that occurs naturally within the pores of rock. Pre- and post-experiment core weighing and nuclear magnetic resonance testing are performed. In addition to the mercury injection tests, the results indicate that during gas reservoir depletion, connate water primarily stems from macropores and mesopores, with micropores and nanopores capturing water through capillary imbibition. Moreover, lower permeability and higher initial water saturation lead to greater pressure gradients, increased connate water production, and reduced recovery efficiency. Reservoirs with permeabilities below 0.1 mD are significantly affected by connate water, exhibiting steep pressure profiles. Owing to connate water, the near-wellbore pressure quickly decreases, while distant reservoir pressure barely decreases, implying a limited drainage area. To enhance the recovery efficiency, measures like infill drilling and reservoir stimulation are recommended for low-permeability gas reservoirs. [ABSTRACT FROM AUTHOR]

In unconventional reservoir engineering, such as coalbed methane and shale gas extraction, fracture behavior is pivotal in gas accumulation, migration, and extraction, acting as a primary channel for gas flow. Current research inadequately addresses the quantitative impact of fracture roughness on gas extraction. In this study, we introduce a novel interdisciplinary model that quantitatively characterizes shale fracture roughness and correlates it with shale permeability. This model comprehensively considers factors affecting shale extraction, including fracture roughness, in situ stress, reservoir deformation, and adsorption-desorption dynamics. It provides a thorough analysis of how fracture roughness influences gas seepage, extraction efficiency, and reservoir stability under various physical conditions. Our validated findings reveal that fracture roughness significantly affects shale permeability, stress responses, and displacement. As the fracture roughness coefficient χ increases from 0.2 to 1.0, the maximum reduction in gas pressure within the hydraulically fractured region is 4.7%, while the maximum increase in reservoir stress is 2.8%. In shale reservoirs near extraction well, particularly in hydraulically fractured zones, the maximum decrease in shale gas pressure is 11.1%, and the maximum increase in stress is 3.2%, which offer a groundbreaking approach for optimizing extraction rates and ensuring project safety in the industry. [ABSTRACT FROM AUTHOR]

Porosity has an important influence on the elastic properties of tight sandstone. Using acoustic models to study the matrix mineral modulus of tight sandstone reservoirs can provide an important reference for tight sandstone reservoir evaluation. In this paper, taking tight sandstone as an example, starting from the microscopic pore scale and considering the heterogeneity of the rock skeleton, the effect of the effective stress coefficient of porosity (n) on the elastic properties of tight sandstone was discussed. In addition, the acoustic model was used to construct the calculation method of the matrix mineral shear modulus. The research results showed that the porosity disturbance model can better describe the change law of the elastic properties of the tight sandstone. As the value of n decreases from 1 to 0, the bulk modulus (Kφ) of the unencapsulated rock gradually decreases. In the process of increasing from n=0 to n=4, the rock Kud has a slight increase trend. The fluid pressure does not produce a reverse stress effect on the movement of the rock pore boundary, that is, the fluid pressure does not have any effect on the change of the rock porosity. When n>0, the pore fluid pressure will affect the movement of the rock pore boundary to a certain extent. When the porosity disturbance is not considered, the Kφ value of the formation rock will be overestimated. The Ko of tight sandstone can be obtained using Gassmann fluid substitution equation. The calculation results of modulus parameters accord with the internal mineral composition and structural characteristics of tight sandstone, which shows the effectiveness of the method. [ABSTRACT FROM AUTHOR]

Reservoir stimulation using hydraulic fracturing technology is one of the most common stimulation measures to develop tight oil and gas reservoirs, and the conductivity of fractures after fracturing is the key to the stimulation effect of oil fields. In this paper, the laboratory simulation system of fracture conductivity is used to study the long‐term fracture conductivity under the displacement of formation water and fracturing fluid. The experimental results show that the fracture conductivity decreases with the increase of displacement time under the displacement of formation water and fracturing fluid, and the decrease of fracture conductivity under the displacement of fracturing fluid with time is greater than that of formation water displacement because of the plugging effect of fracturing fluid residue on pore channels. The use of formation water and fracturing fluid circulation displacement can delay the decline rate of conductivity with time. The conductivity increases with the increase of sand concentration, proppant particle size, and elastic modulus, and decreases with the increase of closure pressure. In addition, by studying the influence of elastic modulus on fracture width, it is found that the smaller the elastic modulus is, the more serious the embedding phenomenon of proppant is, and the smaller the fracture width is. [ABSTRACT FROM AUTHOR]

As coal mining depth increases, there is a corresponding increase in both ground stress and gas pressure, leading to a higher incidence of coal and gas outburst accidents. To investigate the stress distribution law and gas release degree of the adjacent coal body within the goaf of the outburst coal seam, and to acquire an understanding of the impact range of the large mining face goaf on the stress of the coal seam, this study employed theoretical analysis and numerical simulation to analyze the impact and scope of the goaf on the adjacent coal body, and measured the gas content of the coal seam. The findings indicated that following the completion of mining on the working face, there was a redistribution of stress in the coal and rock layers within 40 m of the goaf, with the stress concentration phenomenon observed at a distance of 2.6 m from the goaf. Affected by the stress relief effect of mining, the stress, gas content, and other related factors have been studied in detail by researchers. Affected by the stress relief effect of mining, the stress, gas content, and gas pressure of the surrounding rock near the goaf in the coal seam are significantly reduced. The research results verify that tunneling along the goaf is an effective method to prevent coal and gas outbursts and improve stoping efficiency. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing (HF) is a widely used reservoir reconstruction technology in unconventional oil and gas development. Quantitative characterization of hydraulic fracturing fracture (HFF) is an important way to explore the mechanism of HFF extension and evaluate the stimulation effect of HF. In this study, based on development of HF physical simulation experiments and establishment of mathematical calculation models, the quantitative characterization of fractures induced by HF was systematically explored. The HFF communication area, reservoir reconstruction volume, fractal dimension, and other overall fracture geometry parameters were established. The local geometric characterization parameters of HF such as fracture aperture and fracture occurrence were created. To solve the problem that the calculation of the diameter of the central axis ball was tedious and cannot completely describe the fracture opening, a method to estimate the fracture opening using the shape diameter function was established, and its systematic error was corrected. The mathematical calculation model of HFF seepage properties was established, which is applicable to any complex planar fracture network and provides a new numerical calculation tool for simulating the flow in the fracture. The characteristics of HFF under different compression and shear loads were compared. Highlights: A systematic quantitative characterization method of HFF was presented. The error of estimating fracture aperture by shape diameter function was corrected. The mathematical calculation model of seepage properties was established. [ABSTRACT FROM AUTHOR]

The calculation of the influx index is one of the most contentious issues in dynamic reserve evaluation of gas reservoirs' development. For the influx index, it is key to obtain information on the pore compressibility coefficient under realistic gas reservoir pressure. So far, little is known about the assessment of the pore compressibility coefficient at a laboratory scale. Here, we combine observations of gas flowmeter, ISCO booster pump, intermediate container, and rock samples to quantify the pore compressibility coefficient from the KL2-13 well in the Kela-2 reservoir. Additionally, the iterative method (combined the static and dynamic methods) is proposed based on the experimentally obtained pore compressibility coefficient (Cf), dynamic reserve (G), water body multiple (β), and material balance equation to calculate the influx index. The combined iterative method adjusts the values of G and N by comparing the results of the static and dynamic methods, and iteratively corrects Cf using a binary search method until the results of the static and dynamic methods are consistent. The results of our study reveal that the influx index calculated by the dynamic and static methods was consistent, and the gas production per unit pressure drop matched the actual production. These results strongly suggest that there exists a correlation between formation pressure and the influx index, wherein the latter exhibits a gradual decrease as the former decreases. Conversely, the displacement index of both the rock and connate water do not demonstrate a significant dependence on pressure. Furthermore, the impact of pressure on the pore compressibility factor and reservoir water compressibility factor appears to be minimal. These findings hold substantial implications for understanding the behavior of gas reservoirs under varying pressure conditions. [ABSTRACT FROM AUTHOR]

The condensate gas reservoir with bottom water and oil-rim faces the invasion of oil-rim and bottom water in the process of depleted gas production. In order to explore the invasion mechanism and distribution of oil-rim for a better coping strategy, the long-core displacement apparatus was modified for X-CT scan withstanding high temperature and high pressure (HTHP). From 56.58 to 47 MPa, the oil-gas contact rose fast and gradually slowed down, and the corresponding invasion volume accounted for 82.98% of the total invasion volume. From 47 to 8.8 MPa, the watercut soared to 98% and the invasion rate tended to stagnate. Finally, oil-rim oil was left completely in the reservoir pores and the recovery of condensate oil was only 30.27%. The paper revealed the damage of excessive pressure drop to condensate and oil-rim, and discussed its influencing factors and various pressure control methods. The modified apparatus filled the gap of obtaining oil saturation by X-CT scan under stable HTHP, which had a general application prospect in subsequent optimization and core displacement experiments where oil distribution needed to be observed under HTHP. [ABSTRACT FROM AUTHOR]

The Karakoram fault (KKF) is an important strike‐slip boundary for accommodating deformation following the India‐Asia collision. However, whether the deformation is confined to the crust or whether it extends into the mantle remains highly debated. Here, we show that the KKF is overwhelmingly dominated by crustal degassing related to a 4He‐ and CO2‐rich fluid reservoir (for example, He contents up to ∼1.0–1.6 vol.%; 3He/4He = 0.027 ± 0.013 RA (1σ, n = 47); CO2/N2 up to 3.7–57.8). Crustal‐scale active deformation driven by strike‐slip faulting could mobilize 4He and CO2 from the fault zone rocks, which subsequently accumulate in the hydrothermal system. The KKF may have limited fluid connections to the mantle, and if any, the accumulated crustal fluids would efficiently dilute the uprising mantle fluids. In both cases, crustal deformation is evidently the first‐order response to strike‐slip faulting. Plain Language Summary: Bubbling hot springs are common in fault zones along which Earth's lithosphere cracks. Chemical and isotopic compositions of spring gases can offer key information on the subsurface connectivity of the deep‐rooting faults that is not easily visible. To assess whether the Karakoram fault (KKF) in western Tibetan Plateau is developing in the crust or extends into deeper mantle, we studied the origin and transport of spring gases and found that the KKF is overwhelmingly dominated by degassing of a crustal fluid reservoir that contains high amounts of helium (He) and CO2. This could be attributed to He‐CO2 mobilization of deforming and fracturing fault zone rocks at crustal depths, suggesting that the KKF is primarily developing in the crust and may have limited fluid connections to the mantle. Key Points: New He isotope data show that southern Karakoram fault (KKF) is overwhelmingly dominated by degassing of crustal fluidsA crustal 4He‐ and CO2‐rich fluid reservoir is identified and linked to crustal‐scale active deformation driven by strike‐slip faultingKKF may have limited fluid connections to the mantle and requires further evaluation based on He isotope and seismic data [ABSTRACT FROM AUTHOR]

The creation of temperature variations in magnetization, and hence in the frequencies of the magnon spectrum in laser-heated regions of magnetic films, is an important method for studying Bose–Einstein condensation of magnons, magnon supercurrents, Bogoliubov waves, and similar phenomena. In our study, we demonstrate analytically, numerically, and experimentally that, in addition to the magnetization variations, it is necessary to consider the connected variations of the demagnetizing field. In the case of a heat-induced local minimum of the saturation magnetization, the combination of these two effects results in a local increase in the minimum frequency value of the magnon dispersion at which the Bose–Einstein condensate emerges. As a result, a magnon supercurrent directed away from the hot region is formed. [ABSTRACT FROM AUTHOR]

The over dependence on fossil fuels for human energy requirements together with the resultant adverse environmental effects in the form of greenhouse gas discharges has redirected our attention towards renewable energy sources. Researchers have identified hydrogen, a non-carbonaceous energy source holding the capacity to substitute fossil fuels, as a viable fuel option that has the potential to be generated utilizing eco-friendly techniques. Studies have identified underground sites that are operational or have the potential to be used for hydrogen storage. Shale formations, characterized by their low permeability, offer promising opportunities for underground hydrogen storage. These formations require stimulation techniques to generate flow channels. Pumping frac-fluid into these formations at high pressure induces fractures in them and the engineered fractures are supported by the proppants injected along with the fluid. Propped fractures form a vital conduit in unconventional gas reservoirs, which are a potential medium for storage of hydrogen. Cryogenic fracturing is an innovative approach that aims to enhance and broaden the capabilities of conventional hydraulic fracturing processes. The transmission and settlement of proppants are influenced by certain critical aspects including their density, size and volume fraction and fluid velocity, which are investigated in this contribution. This study incorporates water and cryogenic fluids like liquid nitrogen (LN 2) and liquid helium (LHe) as fracturing fluids. The primary objective of this effort is to analyze proppant transportation phenomenon and the key influential factors in LN 2 and LHe. The proppant volume fraction contour, equilibrium dune level (EqDL) and dune height (EqDH) data are illustrated in this research for better understanding of proppant migration. It was observed that when the fracturing fluid is given a higher velocity, the proppant grains experience increased drag force, causing them to penetrate deeper into the fracture. The desired range of proppant volume fraction for improved grain transmission was determined as 0.45 to 0.50 and the critical proppant density that significantly affected the EqDL as 187.2839 lb/ft3. • Fracturing of impermeable formations for enhanced underground hydrogen storage. • Eulerian-Granular model for studying the proppant bearing ability of cryogenic fluids. • Desired proppant volume fraction range for improved grain transmission is 0.45–0.50 • Higher fluid velocity enables better proppant transportation. • Cryo-fluids carry low-diameter, low-density proppants deeper into the fractures. [ABSTRACT FROM AUTHOR]

A coupled chain of superconductor/ferromagnet/superconductor (S/F/S) with anomalous ground phase shift represents a system realizing long-range interaction between magnetic moments of the weak links. The interaction is of magnetoelectric origin and is mediated by the condensate phase of superconductors. The system is a paradigmic platform for investigation of collective magnetic states governed by the superconducting phase. Here we study the magnetic eigenmodes of such a system and demonstrate that the eigenfrequencies are determined by the magnetic configuration of the whole system and are controlled by the superconducting phase. Depending on the orientation of the magnetic easy axis the eigenmodes can be very different ranging from individual oscillations of different magnets to highly-cooperative behavior. [ABSTRACT FROM AUTHOR]

Marine gas hydrate formations are characterized by considerable water depth, shallow subsea burial, loose strata, and low formation temperatures. Drilling in such formations is highly susceptible to hydrate dissociation, leading to gas invasion, wellbore instability, reservoir subsidence, and sand production, posing significant safety challenges. While previous studies have extensively explored multiphase flow dynamics between the formation and the wellbore during conventional oil and gas drilling, a clear understanding of wellbore stability under the unique conditions of gas hydrate formation drilling remains elusive. Considering the effect of gas hydrate decomposition on formation and reservoir frame deformation, a multi-field coupled mathematical model of seepage, heat transfer, phase transformation, and deformation of near-wellbore gas hydrate formation during drilling is established in this paper. Based on the well logging data of gas hydrate formation at SH2 station in the Shenhu Sea area, the finite element method is used to simulate the drilling conditions of 0.1 MPa differential pressure underbalance drilling with a borehole opening for 36 h. The study results demonstrate a significant tendency for wellbore instability during the drilling process in natural gas hydrate formations, largely due to the decomposition of hydrates. Failure along the minimum principal stress direction in the wellbore wall begins to manifest at around 24.55 h. This is accompanied by an increased displacement velocity of the wellbore wall towards the well axis in the maximum principal stress direction. By 28.07 h, plastic failure is observed around the entire circumference of the well, leading to wellbore collapse at 34.57 h. Throughout this process, the hydrate decomposition extends approximately 0.55 m, predominantly driven by temperature propagation. When hydrate decomposition is taken into account, the maximum equivalent plastic strain in the wellbore wall is found to increase by a factor of 2.1 compared to scenarios where it is not considered. These findings provide crucial insights for enhancing the safety of drilling operations in hydrate-bearing formations. [ABSTRACT FROM AUTHOR]

The form and function of biomolecular condensates are intimately linked to their material properties. Here, we integrate microrheology with molecular simulations to dissect the physical determinants of condensate fluid phase dynamics. By quantifying the timescales and energetics of network relaxation in a series of heterotypic viscoelastic condensates, we uncover distinctive roles of sticker motifs, binding energy, and chain length in dictating condensate dynamical properties. We find that the mechanical relaxation times of condensate-spanning networks are determined by both intermolecular interactions and chain length. We demonstrate, however, that the energy barrier for network reconfiguration, termed flow activation energy, is independent of chain length and only varies with the strengths of intermolecular interactions. Biomolecular diffusion in the dense phase depends on a complex interplay between viscoelasticity and flow activation energy. Our results illuminate distinctive roles of chain length and sequence-specific multivalent interactions underlying the complex material and transport properties of biomolecular condensates. [ABSTRACT FROM AUTHOR]

In view of the short effective period of conventional foam for water shutoff during oil and gas reservoir development, a strong stability gel foam system is proposed in this work. By comparing the foam properties of different foaming systems, the optimized formulation of foam system is "0.3% SDS (sodium dodecyl sulfate) + 0.4% HPAM (partially hydrolyzed polyacrylamide) + 0.3% SD-107 (organic chromium)." At 50 °C and 10 000 mg/l salinities, the volume of foam is basically unchanged after a short time of defoaming and finally remains above 70%, and the drainage half-life can reach 16 days. The polymer and crosslinker form a stable three-dimensional network structure on the Plateau boundary after foaming, which has good viscosity and viscoelasticity. The foam system has excellent temperature and salt resistance. It is appropriate for medium and low temperature shallow reservoirs. The foam system has a good plugging efficiency. It can effectively plug the fracture and improve the sweep volume, which has a good application prospect. [ABSTRACT FROM AUTHOR]

Gas invasion during the drilling process in fractured reservoirs poses challenges, affecting drilling efficiency and increasing costs. Therefore, it is crucial to effectively and accurately describe the flow characteristics of subsurface fluids. Addressing the issue of gas invasion in fractured reservoirs, this study considers the influence of matrix deformation and fracture aperture variation on fluid flow and establishes a mathematical model for coupled flow and solid deformation in fractured reservoirs. The numerical formulation of the mathematical model is derived using the finite element method. To better represent real reservoir conditions, discrete fractures are created using MATLAB, and numerical solutions are obtained using the commercial software COMSOL Multiphysics. The accuracy of the model is verified through a comparison between numerical and analytical solutions. This paper first explores the characteristics of fluid flow within a single fracture and rock deformation when encountering a fracture during drilling. It then compares the predictive capability of the coupled model with that of the uncoupled model in estimating gas invasion. Finally, the primary factors influencing gas invasion in fractured reservoirs are analyzed from the perspectives of rock matrix, fractures, and drilling operations. [ABSTRACT FROM AUTHOR]