Reservoir Formation Research Articles

Comparing acute versus AIDS ART initiation on HIV-1 integration sites and clonal expansion

Early antiretroviral therapy (ART) initiation is known to limit the establishment of the HIV reservoir, with studies suggesting benefits such as a reduced number of infected cells and a smaller latent reservoir. However, the long-term impact of early ART initiation on the dynamics of the infected cell pool remains unclear, and clinical evidence directly comparing proviral integration site counts between early and late ART initiation is limited. In this study, we used Linear Target Amplification-PCR (LTA-PCR) and Next Generation Sequencing to compare unique integration site (UIS) clonal counts between individuals who initiated ART during acute HIV infection stage (Acute-ART group) and those in the AIDS stage (AIDS-ART group). Our analysis revealed distinct clonal distribution patterns, with greater UIS heterogeneity in Acute-ART group and more homogeneity in AIDS-ART group. Monoclonal UIS accumulation, predominantly in-gene regions, was influenced by ART timing and duration, with early treatment delaying this process. Host cell genes integrated by HIV provirus as monoclonal types were enriched in cell cycle and lymphocyte activation pathways. Tumor suppressor genes (TSGs) were more frequently integrated as monoclonal types in AIDS-ART group, suggesting potential risk factors. Overall, we introduced a sequencing method to assess provirus size in human peripheral blood and identified the widespread presence of monoclonal distribution of UIS in AIDS-ART group after long-term treatment. The early intervention helps slow the progress of clonal expansion of infected cells, reducing the formation of stable and persistent reservoirs, and ultimately posing fewer barriers to achieving a functional cure.

Research progress on and outlook of direct CO2 thickeners for enhanced oil recovery.

Supercritical CO2, as an environmentally friendly and pollution-free fluid, has been applied in various EOR techniques such as CO2 flooding. However, the low viscosity of the gas leads to issues such as early breakthrough, viscous fingering, and gravity override in practical applications. Although effective mobility-control methods, such as CO2 WAG (water alternating gas)-, CO2 foam-, and gel-based methods, have been developed to mitigate these phenomena, they do not fundamentally solve the problem of the high gas-oil mobility ratio, which leads to reduced gas sweep efficiency. Adding CO2 direct thickeners to displacing fluid can increase its viscosity, achieve deeper mobility control, and thus improve the CO2 flooding oil-recovery effect. Unlike other methods, direct thickeners can alter the physical and chemical properties of CO2, making it a fundamentally effective means of achieving mobility control. This approach can be applied in various reservoir environments and formations, or it can assist other methods for more in-depth mobility control. This article reviews the development and application of CO2 direct thickeners and introduces the thickening mechanisms and effects of different types of thickeners as well as their existing problems and future development directions.

Reactivity of Wet scCO2 toward Reservoir and Caprock Formations under Elevated Pressure and Temperature Conditions: Implications for CCS and CO2-Based Geothermal Energy Extraction

Reactivity of Wet scCO₂ toward Reservoir and Caprock Formations under Elevated Pressure and Temperature Conditions: Implications for CCS and CO₂-Based Geothermal Energy Extraction

Light Oil Reservoir Source and Filling Stage in the Chepaizi Uplift, Junggar Basin Evidence from Fluid Inclusions and Organic Geochemistry

The light oil wells within the Neogene Shawan Formation have been extensively drilled in the Chepaizi Uplift, reflecting an increase that provides new targets for unconventional resources in the Junggar Basin of northwestern China. However, the original sources of light oil remain controversial, as several source rocks could potentially generate the oil. For this study, we collected light oils and sandstone cores for biomarker detection using gas chromatography–mass spectrometry (GC-MS). Additionally, fluid inclusions were observed and described, and the homogenization temperatures of saltwater inclusions were measured to confirm the oil charging history in conjunction with well burial and thermal history analysis. Based on these geochemical characteristics and carbon isotopic analysis, the results indicate that light oil in the Chepaizi Uplift zone primarily originates from Jurassic hydrocarbon source rocks in the Sikeshu depression, with some contribution from Cretaceous hydrocarbon source rocks. Jurassic hydrocarbon source rocks reached a peak of hydrocarbon generation in the middle to late Neogene. The resulting crude oil predominantly migrated along unconformities or faults to accumulate at the bottom of the Cretaceous or Tertiary Shawan Formation, forming anticlinal or lithologic oil reservoirs. Some oil reservoirs contain mixtures of Cretaceous immature crude oil. During the Neogene light oil accumulation process, the burial rate of reservoirs was high, and the efficiency of charging and hydrocarbon supply was relatively high as well. Minimal loss occurred during the migration of light oil, which significantly contributed to its rapid accumulation.

Ensemble-based assisted history matching of DTS monitoring data in HT-ATES systems: application to a real-life case study

Underground heat storage is an important element in accelerating the energy transition. It can significantly contribute to CO2 emission reduction and cost savings since it is one of the cheapest forms of energy storage and it enables the seasonal storage of large energy surpluses from sustainable sources, e.g. wind, sun, geothermal. Numerical models are used for the prediction of thermal behavior important in establishing the high efficiency of the high temperature aquifer thermal energy storage (HT-ATES) systems. However, the lack of exact knowledge of the subsurface conditions introduces modeling uncertainty. It is therefore important to employ approaches that reduce subsurface uncertainty. History matching is a methodology where the numerical models are updated to match historical observations that will in turn not only increase understanding of the subsurface but also improve accuracy of the model predictability of future behavior. In this research, models of the first large-scale operational HT-ATES system in Middenmeer, the Netherlands, were used to evaluate the thermal evolution in the storage aquifer and the over- and underburden clay layers. The HT-ATES system, consisting of a hot and warm well, with a monitoring well inbetween, became operational in the summer of 2021. The extensive monitoring program implemented for the first few operational years provided an opportunity to study the performance of such a system from an environmental and operational point of view. A state-of-the-art assisted history matching approach was applied to the first storage cycle, using a coupling between history matching software and the thermal flow simulator. This approach was compared to a more traditional single-model manual history matching method. Rock properties of the aquifer and over- and underburden layers were updated in the randomly generated prior ensemble of models to fit the simulated temperature evolution measured down the monitoring well with the distributed temperature sensing (DTS) data. The observations gathered during the second year of operations were used to validate the accuracy of the prediction capabilities of the updated models. The obtained results indicate the value of history matching to improve understanding of the subsurface conditions for HT-ATES systems and obtain models with better predictability of the future behavior of heat in the storage reservoir and overburden formations. Such improved models are instrumental in providing engineers with a better quantitative grip on the environmentally responsible storage potential and heat deliverability of the target storage site, which is important to achieve cost-effective site-specific design (e.g. number of wells, well placement) and performing operational strategies (e.g. injection/production rates and temperatures) for new HT-ATES systems. Moreover, the benefits of the assisted history matching approach over manual method are highlighted and both approaches are validated where the assisted history matching method produced more accurate predictions than the manual approach.

Diagenesis of Deep Low Permeability Reservoir in Huizhou Sag and Its Influence on Reservoirs

The Paleogene Enping Formation in the Huizhou Sag, Pearl River Mouth Basin, has been identified as a key target for deep oil and gas exploration. However, research on the diagenesis of these deep reservoirs still remains limited. This study evaluated the role played by diagenetic processes on the reservoir quality of the Paleogene Enping Formation in the Huizhou Sag, Pearl River Mouth Basin, from braided river deltas to meandering river deltas. A core observation, thin section examination, cathode luminescence analysis, scanning electron microscopy, mercury penetration, porosity–permeability test, and other analytical methods were performed to analyze the diagenesis and its impact on the physical properties of the deep, low-permeability sandstone reservoirs in the Enping Formation within the study area. It was shown that the reservoir composition maturity of the Paleogene Enping Formation in Huizhou Sag is relatively high, and the reservoir space is dominated by dissolved pores, accounting for more than 48.2%. The deep and ultra-deep clastic reservoirs are typically characterized by “low porosity, low permeability, and strong heterogeneity”. In particular, the reservoir space of the deep, low-permeability reservoir of the Enping Formation is significantly affected by diagenesis in which mechanical compaction notably altered the porosity of the Enping Formation reservoir, with a reduction in pore volume ranging from 12.5 to 27.2% (average 18.9%); cementation usually enhances pore reduction by between 2.1 and 28.7% (average 11.7%), while dissolution has resulted in an increase in pore volume ranging from 1.4 to 25.6% (average 10.1%). A further analysis revealed that the deep reservoir type in this region is characterized by “densification”, as evidenced by the correlation between reservoir porosity–permeability evolution and hydrocarbon accumulation.

Diagenesis and Hydrocarbon Charging History of the Late Triassic Yanchang Formation, Ordos Basin, North China

The Yanchang Formation of the Triassic in the Ordos Basin comprises various stratigraphic intervals. The Chang 8 reservoir represents a significant oil-producing section of the Yanchang Formation, and its hydrocarbon accumulation mechanism is complex. In this study, we analyzed the diagenetic evolution and reservoir-forming stages of the Chang 8 member of the Yanchang Formation in the Late Triassic in the Fuxian area, the southern Ordos Basin, via thin-section casting, scanning electron microscopy (SEM), X-ray diffraction, and fluid inclusion petrology and homogenization temperature analyses. The relationship between the petrogenesis and hydrocarbon charging history was analyzed, which provided guidance for identifying and predicting the hydrocarbon reservoir distribution. The results show that the main diagenesis types of the Chang 8 reservoir are compaction, cementation, dissolution, and metasomatism. The comprehensive analysis of the reservoir mineral types, diagenesis, diagenetic sequence, and thermal evolution degree of organic matter shows that the Chang 8 reservoir of the Yanchang Formation is in the A stage of the middle diagenesis stage. Under the overpressure of hydrocarbon generation, oil and gas migrated into the Chang 8 reservoir along fractures and connected pores. The earlier-stage hydrocarbon charging occurred after compaction and later than the early clay film formation and early calcite precipitation, and it also occurred earlier than or simultaneously with the quartz overgrowth. The later hydrocarbon charging occurred after the significant quartz overgrowth and late calcite pore filling. Depending on the homogenization temperature and salinity, the fluid inclusions can be divided into two types: low-temperature, low-salt (90–105 °C, 1.4%–11.2%) fluid inclusions and high-temperature, high-salt (115–120 °C, 2.2%–12.5%) fluid inclusions. According to the analysis of the evolution of the burial history, hydrocarbon charging in the Chang 8 reservoir of the Yanchang Formation in the Fuxian area occurred in two consecutive periods: 133~126 Ma and 122~119 Ma, demonstrating one-scene, two-stage reservoir formation, characterized by simultaneous reservoir densification and hydrocarbon charging. In this research, we precisely ascertained the regional diagenetic characteristics and patterns and periods of hydrocarbon charging, thereby furnishing crucial evidence that deepens the comprehension of sedimentary basin evolution.

Study on Development Characteristics and Reservoir Formation Model of Lower Ordovician Reservoirs in Central Sichuan

Sichuan Basin is a large superimposed petroliferous basin, which has experienced multi-stage extension-convergence cycle and has great potential of oil and gas resources. In recent years, the lower combination oil and gas exploration in the middle Sichuan area has made great breakthroughs in the Sinian Dengying Formation and the Lower Cambrian Longwangmiao Formation, but has not achieved good results in the Ordovician. At present, a number of Wells in the middle Sichuan area show varying degrees of oil and gas in the Lower Ordovician strata, suggesting that the Ordovician strata in this area have the basic conditions for the formation of large-scale oil and gas reservoirs. However, no consensus has been reached on the paleogeographic pattern of Ordovician lithofacies and the distribution of favorable facies zones in this area, and the understanding of reservoir types and reservoir properties is quite different. Therefore, the weak basic research on the geological conditions of reservoir formation has severely restricted the hydrocarbon exploration of the Ordovician in this area. In this paper, the Lower Ordovician lithofacies paleogeography reconstruction and reservoir characteristics analysis are carried out by systematically combing the drilling and field profile data in the central Sichuan area, combined with core observation, thin section identification and reservoir analysis, and finally the Ordovician oil and gas accumulation model is established. The results show that the lithofacies paleogeography distribution of the Lower Ordovician Tongzi-Honghuayuanstage in the central Sichuan area is from the paleo-uplift to the east in the order of platform tidal flat to platform shoal to limited platform. The Lower Ordovician reservoir types in the middle Sichuan area include karst reservoir and dolomite reservoir, among which the karst reservoir is heavily filled and the reservoir performance is limited. The Ordovician reservoir-forming model in the middle Sichuan area reveals a new exploration model of dolomite superimposed bedding under karst in the epicontinental platform, which provides important geological basis for the new breakthrough of Ordovician oil and gas exploration.

Decoding the biogenesis of HIV-induced CPSF6 puncta and their fusion with the nuclear speckle.

Viruses rely on host cellular machinery for replication. After entering the nucleus, the HIV genome accumulates in nuclear niches where it undergoes reverse transcription and integrates into neighboring chromatin, promoting high transcription rates and new virus progeny. Despite anti-retroviral treatment, viral genomes can persist in these nuclear niches and reactivate if treatment is interrupted, likely contributing to the formation of viral reservoirs. The post-nuclear entry dynamics of HIV remain unclear, and understanding these steps is critical for revealing how viral reservoirs are established. In this study, we elucidate the formation of HIV-induced CPSF6 puncta and the domains of CPSF6 essential for this process. We also explore the roles of nuclear speckle scaffold factors, SON and SRRM2, in the biogenesis of these puncta. Through genetic manipulation and depletion experiments, we demonstrate the key role of the intrinsically disordered region of SRRM2 in enlarging nuclear speckles in the presence of the HIV capsid. We identify the FG domain of CPSF6 as essential for both puncta formation and binding to the viral core, which serves as the scaffold for CPSF6 puncta. While the low-complexity regions (LCRs) modulate CPSF6 binding to the viral capsid, they do not contribute to puncta formation, nor do the disordered mixed charge domains (MCDs) of CPSF6. These results demonstrate how HIV evolved to hijack host nuclear factors, enabling its persistence in the host. Of note, this study provides new insights into the underlying interactions between host factors and viral components, advancing our understanding of HIV nuclear dynamics and offering potential therapeutic targets for preventing viral persistence.

Geochemical characteristics and depositional conditions of the Lower-Middle Jurassic source rocks in the Southern margin of the Junggar Basin, NW China

The Lower-Middle Jurassic source rocks are identified as the primary contributors along the southern margin of the Junggar Basin. To elucidate their geochemical characteristics, a comprehensive and unprecedented collection of deep Basin (>4500 m) source rock samples was undertaken in the region. A systematic analysis of 124 samples was performed, including studies on organic carbon, Rock-Eval, and organic petrology. Additionally, Gas Chromatography-Mass Spectrometry (GC-MS) analysis was conducted on 21 selected samples. The findings reveal that the Lower-Middle Jurassic source rocks were deposited in a weakly oxidizing to reducing freshwater environment, predominantly comprising liptinite, and vitrinite organic macerals, with a high abundance of Types III and II organic matter. Maturity assessments indicate a varied reservoir formation potential along the southern margin of the Junggar Basin, with the western part generally exhibiting lower maturity levels compared to the central and eastern regions. This suggests that condensate gas reservoirs are more likely to form in the central and eastern areas, while the western part is more favorable for oil reservoir formation. These results underscore the “source control” characteristics of the southern margin of the Junggar Basin.

Experimental Study on the Alternate Oil Displacement Mechanism of CO2 and Modified Water in Low-Permeability Oil Layers

Alternating carbon dioxide and water flooding can not only seal greenhouse gases, but also combine the advantages of water flooding and carbon dioxide flooding, and can well control mobility and stabilize the displacement front, thereby greatly improving the macro-replacing efficiency. In order to further improve the development effect of water–carbon dioxide alternating flooding, this paper, based on sufficient collection of the literature, research, and analysis, pre-uses modified water instead of water, and deeply explores and studies the impact of modified water–carbon dioxide alternating flooding on the improvement of development effect and the mechanism of enhancing oil recovery in low-permeability reservoirs. The main work completed is as follows: (1) A comparative experiment of multiple groups of sand-filled tubes with different displacement media, modified water concentrations, and injection plug sizes was conducted under the conditions of simulating reservoir formation temperature of 70 °C and formation pressure of 18 MPa, and the optimal scheme and injection parameters of alternating modified water and carbon dioxide flooding were rationally selected. The results show that the alternating flooding of modified water and carbon dioxide in low-permeability reservoirs can significantly improve the development effect. The optimal injection parameters are a formulation concentration of 0.3% and an injection method of alternating a 0.1 PV slug injection of carbon dioxide and modified water. (2) Using Berea cores instead of sand-fill tubes, a comparative experiment of alternating oil displacement using carbon dioxide and modified water was carried out under the same experimental conditions. Nuclear magnetic resonance measurements were performed on five of the cores to analyze the microscopic oil displacement mechanisms of different displacement media. The results show the following: nuclear magnetic resonance testing shows that carbon dioxide displacement can greatly improve the oil recovery efficiency in tiny pores (about 47.43%); alternating injection can further improve the oil recovery efficiency in tiny pores (about 70.6%); and modified water can improve the oil recovery efficiency in larger pores (about 56.47%).

УСЛОВИЯ НЕФТЕГАЗОНОСНОСТИ ВЕРХНЕЮРЯХСКОГО ГОРИЗОНТА НА СЕВЕРО-ВОСТОКЕ НЕПСКО-БОТУОБИНСКОЙ АНТЕКЛИЗЫ

The Yuryakha productive horizon is one of the most promising objects for a significant increment in the hydrocarbon resource base in the Republic of Sakha (Yakutia). Its low reservoir properties and compound distribution of the improved reservoir zones are noted. The analytical review of scientific notations about the relationship between petroleum potential of deposits and basement highs is carried out. The absence of lithological varieties in deposits and their thicknesses is shown on the basis of facies analysis of the Yuryakha Formation sections above basement highs and beyond. The influence of basement highs on the productivity of the Yuryakha Horizon is assumed to be limited by creating conditions for the development of secondary processes that potentially increase the void space. It is concluded that the search for zones of improved reservoirs in the Yuryakha formation based on paleogeographic reconstructions is a more promising direction than the justification of point sites with secondary changes.

VSP Modeling With The Reflectivity Method And Semblance Processing

The present work deals with a specific detail of the VSP technique for estimating local compressional, 𝑣𝑃, and shear, 𝑣𝑆 , wave velocities focused on reservoir characterization and seismic interpretation in sedimentary basins. This investigation was based on the presence of fluids (water, oil, gas) in porous rocks and its relationship with the 𝛾 = 𝑣𝑆 𝑣𝑃 ratio, which mainly affects the shear wave velocity. The forward modeling was based on the reflectivity method to simulate seismic sections along depth in the borehole, considering the presence of a reservoir formation with an anomalous 𝛾 ratio value. The seismic processing of the vertical, transversal, and radial components produced by VSP modeling was based on band-pass filtering for upward and downward field separation, semblance picking, and NMO correction for estimating 𝑣𝑃 and 𝑣𝑆 wave velocities. Additionally, we compare different semblance measures to validate the NMO correction. The results show an accurate estimate of the 𝛾 ratio in the target layer, even considering receivers at different depths and high noise levels in the VSP sections. Besides that, the 2D numerical experiment reveals information about the sensitivity of the 𝛾 parameter in a layered medium with velocity variation, principally around regions with the potential presence of oil and gas.

Characteristics and Genesis of Heavy Oil in Shallow and Thin Layers in Chepaizi Area, Xinjiang, China

The Neoproterozoic Shawan Formation in the Chepaizi area is recognized for its significant heavy oil resources. Investigating the underlying causes and mechanisms of heavy oil changes in accordance with the specific characteristics of the reservoir is crucial for future exploration and development. The distribution of heavy oil in the Pai 612 block was identified to present a combination of shallow and thin deposits, high porosity, high permeability, and elevated water content. The physicochemical properties of the crude oil included a complex composition, high density, high viscosity, substantial gel content, and notable oxidation-biodegradation potential. The oxidation and biodegradation of crude oil during transportation played the critical roles in the formation of heavy oil. As cru3de oil was transported upward, the formation temperature decreased, resulting in increased viscosity. An excess of water could initially increase and subsequently decrease heavy oil viscosity, while groundwater in the reservoir contained various chemicals that interacted with colloids and asphaltenes, further increasing the viscosity. During the formation of the early heavy oil reservoir, the light oil was unable to dissolve and transport the high-molecular-weight asphaltene component, leading to the high resin content in the heavy oil of the Pai 612 block.

Star formation in neutral hydrogen gas reservoirs at cosmic noon

We aim to constrain the average star formation associated with neutral hydrogen gas reservoirs at cosmic noon. We used a unprecedented sample of 1716 high-column-density, damped Ly-alpha absorbers (DLAs) from the Sloan Digital Sky Survey with log($N$(H i $) ge 21. This allowed us to generate the average Ly-alpha emission spectrum associated to DLAs, free from any emission coming from the background quasar. We measured the Lyalpha emission at $> 5.8 level with a luminosity of $8.95 erg s $ (corresponding to about 0.02 L$^ star $ at $z 2-3) in systems with average i $) of approx 21.2 and at a median redshift of $z 2.64. The peak of the Lyalpha emission is apparently redshifted by sim 300 $ relative to the absorption redshift, which appears to be due to suppression of blue Ly-alpha photons by radiative transfer through expanding gas. We infer that DLAs form stars with an average rate of (0.08 pm 0.01)/$ f esc M odot yr $; namely, $ M odot yr $ for a typical escape fraction ($ f esc =0.15$) of Lyman-alpha emitting galaxies. DLA galaxies follow the main sequence of star-forming galaxies at high redshift, suggesting that the DLA population is dominated by the lower mass end of Lyman-alpha emitting galaxies.

Structural Characteristics of the Fault Zone and Fault-Controlled Hydrocarbon Accumulation in the Chenghai Area of Dagang Offshore.

The Chenghai area is a secondary structural unit within the Qikou sag of the Bohai Bay Basin, located in the southern part of the Dagang offshore area, known for its abundant oil and gas resources. Influenced by multiple episodes of tectonic activity, the Chenghai area exhibits a highly developed fault system, which significantly impacts oil and gas exploration in the region. To investigate the structural characteristics of fault zones in the Chenghai area and their petroleum geological significance, this study builds upon previous research by utilizing oilfield drilling data and relevant seismic information. Through methods such as fault growth index analysis, structural evolution history, and examination of typical oil and gas reservoir profiles, a detailed structural analysis of fault-controlled hydrocarbon accumulation in this petroleum region was conducted. The results reveal three types of fault classifications in the study area: basal-controlled continuously active faults, buried reactivated segmented growth-connected faults, and late-stage continuously active isolated growth faults. The structural evolution is divided into four stages: the pre-Paleogene basement formation stage, the Rifting I stage of intense extensional deformation, the Rifting II stage of extensional stress reversal and intense deformation, and the post-Eocene weak extensional deformation-stable burial stage. The fault-controlled accumulation models include three types: fault-guided longitudinal accumulation, lateral sealing fault masking accumulation, and far-source step-like fault-guided accumulation. The formation of fault zones and fault-controlled oil and gas reservoirs in the Chenghai area is primarily influenced by inherited development faults, which determine the overall macroscopic distribution of oil and gas. The formation of oil and gas reservoirs occurred relatively late, with a general trend of decreased fault activity during this period, facilitating the effective accumulation and sealing of hydrocarbons.

Deciphering the Impact of the Active Lithium Reservoir in Anode-Free Pouch Cells

Anode-free batteries, which revolutionize energy storage by discarding traditional anodes in favor of copper foil to plate lithium directly from the cathode, offer increased energy densities and better safety than conventional lithium-metal cells. However, their advantage is tempered by a significantly reduced cycle life, attributed to lithium loss through parasitic reactions. As a result, inactive (‘dead’) lithium accumulates over cycling, including (electro)chemically formed Li+ compounds in the solid electrolyte interphase (SEI) and isolated unreacted metallic Li0, resulting in capacity loss and safety hazards. Consequently, to continue enhancing the performance of anode-free cells, it appears crucial to differentiate and quantify the various forms of lithium in these cells and monitor their distribution and evolution throughout the cycling process, depending on various conditions such as pressure or electrolytes.Compared to lithium metal cells, the problem might appear simplified for anode-free cells as there is no active lithium compensation from the anode, and all the active lithium is initially stored within the cathode. However, the intricate interplay of the cathode's first-cycle irreversibility and lithium plating/stripping efficiency significantly influences the shape of the capacity retention curves and the measurements of coulombic efficiency (CE). Herein we aim to clarify the contribution of the lithium reservoir to the anode-free cell performances. We report a systematic study of the active lithium reservoir and unreacted metallic Li0 evolution in anode-free LiNi0.6Mn0.2Co0.2O2 (NMC622)||Copper (Cu) commercial pouch cells. By taking advantage of a discharge characteristic of the NMC622 cathode at low voltage (<1.5 V), we could quantify the presence of remaining active lithium at the anode. Afterwards, titration gas chromatography was utilized to measure the remaining inactive Li0 on the discharged samples. By coupling the quantification techniques to observations of the anode local microstructure by cryogenic scanning electron microscopy, we elucidate the formation and evolution mechanism of the lithium reservoir and inactive metallic lithium in different types of electrolytes.As a result, we demonstrated that the once-considered drawback of Ni-rich layered oxide cathodes, namely the first cycled intrinsic irreversible capacity, can be manipulated to build a lithium reservoir at the anode and extend the cycle life of anode-free cells (see Figure 1, bottom left). Additionally, the formerly unclear reason for the capacity degradation discrepancy of anode-free cells under different C-rates was investigated and attributed to the correlation between lithium utilization and reservoirs (see Figure 1, bottom right). In contrast to the first-cycle irreversibility unique to certain types of cathode materials, this approach can be applied to all types of cells having polarization phenomena at high currents to enhance their longevity in anode-free configurations. Consequently, by employing protocols with slow charge and fast discharge, the lithium reservoir at the anode is maximized, and the performances of the anode-free cells appear stable for a longer number of cycles. With this knowledge, one can regulate the ratio between lithium utilization and lithium reservoirs for extended capacity retention or high initial reversible capacity designated for different applications. We believe the concept of this Li reservoir can be further extended to other approaches and opens new opportunities, taking advantage of cathode intrinsic irreversibility and kinetic limitations to extend anode-free cells’ lifespan. Figure 1

Hydrogen, Methane, Brine Flow Behavior, and Saturation in Sandstone Cores During H2 and CH4 Injection and Displacement

Large-scale underground hydrogen storage (UHS) is a critical component in the emerging hydrogen economy. Knowledge of multiphase flow behavior involving hydrogen in storage reservoir formations is crucial to characterizing hydrogen transport properties and essential for the deliverability and storage operations of UHS. There are still many gaps in fully understanding hydrogen–methane–brine multiphase phase flow that require further investigation. In this work, H2 and CH4 were injected through brine-saturated sandstone cores using a tri-axial core holder system fitted with flow rate meters and pressure transducers, while the effluent gas concentrations were analyzed using an online micro gas chromatograph. Brine displacement, permeability, and gas breakthrough curves were measured. We studied the flow behavior of hydrogen and methane in sandstone cores through testing brine displacement by gas injection and comparing the hydrogen displacement of methane with the methane displacement of hydrogen. We also tested the differences between horizontal and vertical flow in brine displacement. The results showed that brine displacement was more efficient in a core with higher permeability and porosity, resulting in a higher initial gas saturation. A higher gas injection rate brought about faster gas breakthrough measured by pore volume and sharper concentration curves. Hydrogen did not exhibit abnormal flow in the sandstone when the flow was horizontal and downward vertical. Gas overriding was observed in brine displacements when the flow was horizontal, with hydrogen showing this behavior more profoundly compared to methane. Downward vertical gas injection induced higher efficiency brine displacement compared to horizontal displacement and resulted in a higher initial gas saturation in the sandstone cores. These findings address critical knowledge gaps regarding gas flow patterns and displacement behaviors during hydrogen injection and recovery phases in UHS facilities using methane as the cushion gas. The insights from this research offer valuable guidance for optimizing UHS systems, ensuring operational efficiency, and advancing sustainable energy solutions in alignment with decarbonization goals.

Physical and experimental simulation of unconventional reservoir formation for carboniferous in hudson oilfield, Tarim Basin, China

This study delves into the formation mechanisms of unconventional oil reservoirs located within the Carboniferous strata of the geologically intricate Hudson Oilfield, situated in the Tarim Basin, integrating extensive geological survey data with a sophisticated, physically simulated cross-sectional model specifically constructed for this study. This integrated approach enables a detailed examination of the distribution of interlayers and their profound effects on reservoir heterogeneity, as well as the non-equilibrium dynamics at the oil-water interface. Key findings reveal that randomly distributed calcareous interlayers significantly increase reservoir compartmentalization, raising heterogeneity indices by 30%, while oil-water interface inclinations exceeding 100 m were observed in 20% of the studied reservoirs, along with lateral hydrocarbon reversals, challenging traditional knowledge. Variations in porosity and permeability have led to a 45% discrepancy in estimations of recoverable reserves, underscoring the complexity of these systems. Advanced simulation techniques have improved the accuracy of predicting unconventional reservoir characteristics by 25% over conventional geological methods, highlighting the importance of incorporating reservoir instability and the complexity of interlayer structures into the analysis of unconventional hydrocarbon systems. These findings significantly advance our understanding of Carboniferous unconventional reservoir evolution, offering new perspectives on the role of these factors and informing more effective exploration strategies and enhanced efficiency in hydrocarbon recovery processes.

Combined use of petroleum inclusion analysis, PVT simulation, and basin modeling for reconstruction of deep fluid phase evolution in condensate gas reservoirs

The reconstruction of the fluid phase evolution in deep condensate gas reservoirs can reveal the mechanism of condensate gas formation, facilitating the early formulation of drilling strategies. However, the complexity of petroleum fluid phase evolution during hydrocarbon generation, migration, and accumulation poses numerous challenges for the reconstruction process. Therefore, petroleum fluid inclusion analysis, PVT phase simulation, and basin modeling were used to achieve the reconstruction of phase states during key geological periods, elucidating the phase evolution of the deep condensate reservoirs in the Dongying Depression during the whole process. The modeled results show that the mature source rocks contributed to the charging and accumulation of liquid oils (38–14 Ma). Next, a low oil cracking conversion rate limited the increase of gaseous hydrocarbon fraction, so the accumulated hydrocarbons remained in a liquid phase (14–0 Ma). The late external gas inputs significantly increased the gas-oil ratio in the reservoirs, leading to the transition from the liquid oil phase to the condensate phase (5–0 Ma). The fluid compositions obtained from hydrocarbon inclusions and the physical properties of present-day condensates can effectively constrain basin modeling, leading to reliable simulation results. This work revealed that the hydrocarbon generation controls the initial hydrocarbon components in the traps for the phase evolution. Furthermore, the secondary alterations including oil cracking and gas inputs influence the proportion of methane of petroleum in the deep reservoirs, which dominates the phase evolution. Deep petroleum fluid phase changes mainly require the molar ratio of the input gas more than 50%. A model was proposed to explain the formation of deep condensate reservoirs. A series of gas inputs and escape in the successive lithological traps controls an orderly phase change of deep petroleum, and the amount of deeper gas determines the range of the existence of condensate gas reservoirs. This study not only guides the exploration of deep condensate in the Dongying Depression but also offers a workflow for the research on the formation and evolution of condensate reservoirs in other global regions.