Reservoir Conditions Research Articles

Excited electronic states of Na2 and K2: The potential for long-lived "reservoir" states leading to collision induced population inversions.

Potential energy curves (PECs) for the spin-free (ΛS) and spin-orbit (Ω) states associated with the four lowest-lying dissociation channels of Na2 and K2 were calculated at the SA-CASSCF/SO-CASPT2/aug-cc-pwCVQZ-DK level. The PECs of Na2 were consistent with the experimental data and with the FS-CCSD (2,0) calculations, reproducing the double-well and the "shelf" character for some of the potentials of the excited states. For K2, the PECs behaved in a similar way and the spectroscopic parameters for the ground and the excited states are in good agreement with the available experimental values. The dissociation energy of K2 was predicted to be De = 4454cm-1, within an agreement of 5cm-1 with the experiments. For Na2, De = 5789cm-1 compared to the experimental value of 6022cm-1. The inclusion of spin-orbit coupling effects resulted in avoided crossings, which affect the PECs. Spin-orbit changes the predicted curves for some excited Ω states arising from ΛS states that overlap each other, affecting their associated vibrational frequencies and bond distances. The current studies of the low-lying states in K2 reveal a similar structure to those of Na2, which suggests the accessibility of long-lived energy storing reservoir states and possible population inversions in K2 following prior experimental work on the reaction of halogen atoms with Na3 to produce excited states of Na2.

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

Carbon capture and storage (CCS) and CO2-based geothermal energy are promising technologies for reducing CO2 emissions and mitigating climate change. Safe implementation of these technologies requires an understanding of how CO2 interacts with fluids and rocks at depth, particularly under elevated pressure and temperature. While CO2-bearing aqueous solutions in geological reservoirs have been extensively studied, the chemical behavior of water-bearing supercritical CO2 remains largely overlooked by academics and practitioners alike. We address this knowledge gap by conducting core-scale laboratory experiments, focusing on the chemical reactivity of water-bearing supercritical CO2 (wet scCO2) with reservoir and caprock lithologies and simulating deep reservoir conditions (35 MPa, 150 °C). Employing a suite of high-resolution analytical techniques, we characterize the evolution of morphological and compositional properties, shedding light on the ion transport and mineral dissolution processes, caused by both the aqueous and nonaqueous phases. Our results show that fluid-mineral interactions involving wet scCO2 are significantly less severe than those caused by equivalent CO2-bearing aqueous solutions. Nonetheless, our experiments reveal that wet scCO2 can induce mineral dissolution reactions upon contact with dolomite. This dissolution appears limited, incongruent, and self-sealing, characterized by preferential leaching of calcium over magnesium ions, leading to supersaturation of the scCO2 phase and reprecipitation of secondary carbonates. The markedly differing quantities of Ca2+ and Mg2+ ions transported by wet scCO2 streams provide clear evidence of the nonstoichiometric dissolution of dolomite. More importantly, this finding represents the first reported observation of ion transport processes driven by water continuously dissolved in the scCO2 phase, which challenges prevailing views on the chemical reactivity of this fluid and highlights the need for further investigation. A comprehensive understanding of the chemical behavior of CO2-rich supercritical fluids is critical for ensuring the feasibility and security of deep geological CO2 storage and CO2-based geothermal energy.

Research on shale dynamic and static elastic modulus and anisotropy based on pressurization history

The dynamic and static elastic parameters of rocks exhibit differences. It is of great practical significance to carry out experiments on dynamic and static elastic parameters of rocks under reservoir conditions and determine the conversion relationship between dynamic and static elastic parameters. In this study, shale oil samples from the second member of Kongdong sag in Dagang Oilfield were analyzed by triaxial compression experiments at different bedding angles and longitudinal and shear wave velocity tests. Dynamic and static stiffness coefficient, elastic modulus and acoustic wave velocity change under different directions of pressure and pressure relief. The results indicate that the P-wave velocity, fast shear wave velocity, slow shear wave velocity, dynamic and static Young’s modulus exhibit an increase as the confining pressure rises, and the parameters are greater during the unloading process than during loading process. At identical confining pressures, the dynamic Young’s modulus measured by cores with parallel bedding plane is greater than that measured by cores with vertical bedding plane. The dynamic and static elastic mechanical parameters of different bedding angles can be transformed under varying pressures, and the dynamic elastic mechanical parameters measured under varying levels of confining pressure can be transformed into static elastic mechanical parameters under equivalent confining pressures, which offer fundamental parameters for examining rock mechanics properties and serving as a reference for developing fracturing construction plans for oil and gas reservoirs.

Molecular Insights into the Control Mechanism of the Solid-Liquid Interface Interaction on Shale Oil Occurrence: Grand Canonical Monte Carlo and Molecular Dynamics Simulations Investigation.

The strong solid-liquid interaction leads to the complicated occurrence characteristics of shale oil. However, the solid-liquid interface interaction and its controls of the occurrence state of shale oil are poorly understood on the molecular scale. In this work, the adsorption behavior and occurrence state of shale oil in pores of organic/inorganic matter under reservoir conditions were investigated by using grand canonical Monte Carlo (GCMC) and molecular dynamics (MD) simulations. The adsorption potential energy and interaction energy were quantitatively evaluated, and the control mechanism of the oil-rock interaction on shale oil occurrence was explained. Results show that the density distribution of shale oil is not uniform under the confined space. Multiple layers of adsorption of n-octane occur in graphene pores. The number of adsorbed layers is mainly affected by pore size. With the increasing temperature and pore size, the adsorption site shifts from the high-energy to low-energy site and the solid-liquid interaction weakens. The effect of pressure on the occurrence state can be ignored due to capillary condensation. Minerals and oil chemical compositions also affect the oil-rock interaction and occurrence state. The adsorption intensity of minerals to n-octane decreases in the order graphene > montmorillonite > quartz. Competitive adsorption occurs among oil components. The adsorption order of oil components in graphene is asphaltenes > resin > nonhydrocarbon compound > aromatic hydrocarbons > saturated hydrocarbons. Asphaltenes preferentially adsorb on the surface of organic matter and occupy most of the adsorption surface, while saturated hydrocarbons mainly adsorb on the surface of heavy components or distribute in the pore center. The molecular structure of hydrocarbons also affects the adsorption characteristics. The long-chain hydrocarbons preferentially adsorb on the surface more than short-chain hydrocarbons. The straight-chain hydrocarbons preferentially adsorb more than the branched-chain hydrocarbons. This study provides the microscopic interaction between shale oil and minerals and explores the effect of the control mechanism of the oil-rock interfacial interaction on the occurrence state at the molecular level.

Deep hydrocarbon charging and accumulation in complex fault blocks, the northern part of the eastern Liaohe depression, China

Deep exploration in complex fault-block regions is critical for global oil and gas development. As a representative region characterized by complex fault-block development, the northern part of the eastern Liaohe depression poses challenges in understanding the charging time and migration channels of deep hydrocarbons due to its intricate structural and reservoir conditions. For this purpose, this study utilizes diverse geological data from recent explorations, employing the petrological characteristics of inclusions, homogenization temperatures, and simulations of the thermal burial history to investigate the charging times of deep hydrocarbons. It combines the diagenetic processes of the reservoir with tectonic evolution to reveal the charging pathways and dynamic processes of deep hydrocarbons in the northern part of the eastern Liaohe depression. The results indicate that there are two charging periods in the study area: the late Oligocene (32.9–27.5 Ma) and from the late Neogene to the present (8.7–0 Ma). During these critical periods, faults with high activity intensity and low fault section normal stress were in an open state, which can serve as pathways for the vertical long-distance migration of hydrocarbons. In the first charging period, a substantial volume of hydrocarbon expelled from the source rocks migrates vertically into the deep sandstone reservoir through opening faults, exhibiting characteristics of source–reservoir separation. Subsequently, a brief uplift at the end of the Oligocene halted hydrocarbon generation. In the second charging period, as the source rocks further matured, a substantial volume of natural gas was injected into the deep reservoirs. At this period, the faults approached the seal, preventing hydrocarbons from migrating vertically and allowing them to enter the deep sandstone reservoirs adjacent to the source rocks, reflecting characteristics of source–reservoir proximity.

A Novel Exopolysaccharide Produced by Sphingomonas sp. MT01 and Its Potential Application in Enhanced Oil Recovery.

Sphingan is a crucial exopolysaccharide (EPS) produced by Sphingomonas genus bacteria with wide-ranging applications in fields such as food, medicine, and petroleum. In this study, a novel sphingan, named MT gum, was overproduced from the wild-type strain Sphingomonas sp. MT01 at a yield of 25.6 g/L in a 5 L fermenter for 52 h at 35 °C. The MT gum was mainly composed of D-glucose (65.91%) and L-guluronic acid (30.69%), as confirmed by RP-HPLC, with Mw 7.24 × 105 Da. The MT gum exhibited excellent rheology and pseudoplasticity characteristics while maintaining function in high-temperature and high-salinity environments. The viscosity retention rates of MT gum (0.1%, w/v) were 54.06% (80 °C, 50,000 mg/L salinity) and 34.78% (90 °C, 50,000 mg/L salinity), respectively. The apparent viscosity of MT solutions (0.1%, w/v) was much higher than that of welan solutions under the same conditions. The MT gum also had the property of instant dissolution and completely swelled in 40 min. Meanwhile, the MT gum was resistant to 3-10 mg/L Fe2+ in the reservoir conditions, ensuring its application in offshore oil fields. These findings suggested that the biopolymer MT gum produced by the strain MT01 had significant potential in enhanced oil recovery (EOR) of high-temperature and high-salinity oil reservoirs.

Experimental Study of Geochemical Interaction of Carbon Dioxide With Formation Water and Rock of Water-Saturated and OilSaturated Horizons

The paper presents results of the experimental study of geochemical processes in the “formation water – CO – rock” system at reservoir conditions for waterand oil-saturated intervals of several typical terrigenous and carbonate formations of Urals-Volga region. Compositions of formation water and dissolved gas are analyzed at each stage of the experiments, as well as mineral composition of core samples before and after the interaction. Based on the experimental results, a summarizing analysis is presented of possible physical and chemical processes occurring in the “formation water – CO2– rock” system during carbon dioxide injection into waterand oil-bearing formations. The results of the experiments allow us to highlight the significant effects of dissolution and resuspension of carbonates and halite during exposure of carbonized formation water with core material of different lithology and saturation character. In a number of experiments, significant changes in the iron and sulfate anions content were recorded, indicating the interaction of the solution with pyrite and gypsum. There were no significant qualitative and quantitative differences in the results of experiments with core material from water-saturated and oilsaturated intervals of the same lithology.

A Critical Review of the Phenomenon of Inhibiting Asphaltene Precipitation in the Petroleum Industry

This comprehensive review examines chemical and nano-based methods for asphaltene inhibition in the oil industry, focusing on recent developments and challenges. Asphaltene precipitation and deposition remain significant challenges in oil production, affecting wellbore areas, equipment walls, and surface infrastructure. The review analyzes various chemical inhibition mechanisms and evaluation methods, highlighting the emergence of nanotechnology as a promising solution. Metal oxide nanoparticles, organic nanoparticles, and inorganic nonmetal nanoparticles are discussed as effective inhibitors, with particular attention to their performance in different operational conditions, including CO2 flooding processes. The study reveals that nanoparticles’ effectiveness in asphaltene inhibition is attributed to their large specific surface area, strong adsorption capacity, and unique interaction mechanisms with asphaltene molecules. The review also emphasizes the importance of proper inhibitor selection and concentration optimization, as the effectiveness thereof varies with reservoir conditions and crude oil characteristics. Recent developments in functionalized nanoparticles and their applications in enhanced oil recovery are examined, providing insights into future directions for asphaltene management in the petroleum industry.

Study of the Influence of Well Operation Parameters of a Carbonate Reservoir Oil Formation on the Coefficient of Productivity Using Statistical Methods of Analysis

Well productivity index is one of the most important indicators for the development of carbonate reservoirs of oil fields, control and maintenance of high values of which determines the levels of hydrocarbon production. Determination of the complex influence of geological and technological factors on production capabilities of wells remains an actual direction of research in the field of oil producing. The present paper is devoted to improving the efficiency of production wells in a carbonate reservoir oil deposit based on the results of evaluation and consideration of the relationship between the productivity index and geological and field parameters such as reservoir pressure, bottomhole pressure, skin-factor, gas-oil ratio, water cut, using statistical methods of analysis. At the stage of preparation of initial data the materials of hydrodynamic and production-geophysical studies performed on the wells during the whole period of development of oil reservoir of one of the fields of Perm region were involved. The analysis of the obtained data sample with the use of statistical methods allowed us to study the relationships between the specific well productivity index and the considered geological and production parameters. Multivariate statistical models were developed using stepby-step regression analysis, collectively demonstrating the predominant influence of bottomhole pressure, reservoir pressure and water cut on the specific well productivity index based on the frequencies of occurrence of parameters and the order of their inclusion in the model. The study of the dynamics of changes in the accumulated multiple correlation coefficient during the development of statistical models allowed us to identify the ranges (areas) of change in the values of the specific well productivity index, which are characterized by individual correlations with geological and production parameters described by the corresponding mathematical dependencies. The developed models are characterized by high quality, which is confirmed by their statistical evaluations when comparing forecast and factual values of specific well productivity index. The criteria of applicability of models for conditions of carbonate reservoirs of oil fields are formed. The results of the study can be used for justification and regulation of technological modes of well operation, planning programs of optimization measures.

The Evolution of Hydraulic Fracturing Technologies for the Carbonate Sediments of the Kashirsky and Podolsky Horizons of the Arlanskoe Oilfield

This article reviews the evolution of hydraulic fracturing (HF) technologies for the carbonate sediments of the kashirsky and podolsky horizons of the Arlanskoe oilfield (the Republic of Bashkortostan and the Udmurt Republic) by the influence of changes in current development conditions, reserve depletion, clarification of the geological structure, and scientific and technical advancements. It presents an overview of the main technologies of primary hydraulic fracturing and re-fracturing actively used today and/or are being introduced on the industrial scale. For horizontal wells, hydraulic fracturing with hydraulic jet perforation (HJP) is employed. This technology enables the development of previously untapped or underperforming sections of the wellbore by allowing selective acid and proppant injection into specific intervals, offering high controllability and predictability. Both HJP and HF stages are completed in a single tripping operation without the need for a coiled tubing fleet. For directional wells, high-tonnage hydraulic fracturing with increased proppant mass up to 40–50 tons is a promising technological solution. This approach enhances to increase starting oil flow rates by improving coverage ratio due to involving poorly drained and previously undeveloped overlying and underlying layers. The article consolidates practical experience with hydraulic fracturing technologies, analyzes their effectiveness, identifies the features of hydraulic fracturing in directional and horizontal wells, and develops an algorithm for the selection of hydraulic fracturing technology for the conditions of a carbonate reservoir.

Harnessing spatiotemporal transformation in magnetic domains for nonvolatile physical reservoir computing.

Combining physics with computational models is increasingly recognized for enhancing the performance and energy efficiency in neural networks. Physical reservoir computing uses material dynamics of physical substrates for temporal data processing. Despite the ease of training, building an efficient reservoir remains challenging. Here, we explore beyond the conventional delay-based reservoirs by exploiting the spatiotemporal transformation in all-electric spintronic devices. Our nonvolatile spintronic reservoir effectively transforms the history dependence of reservoir states to the path dependence of domains. We configure devices triggered by different pulse widths as neurons, creating a reservoir featured by strong nonlinearity and rich interconnections. Using a small reservoir of merely 14 physical nodes, we achieved a high recognition rate of 0.903 in written digit recognition and a low error rate of 0.076 in Mackey-Glass time series prediction on a proof-of-concept printed circuit board. This work presents a promising route of nonvolatile physical reservoir computing, which is adaptable to the larger memristor family and broader physical neural networks.

Integrated Identification and Efficient Use of Biodiversity in Mountainous Regions

The article studies the comprehensive identification and efficient use of biodiversity (geothermal sources) in mountainous regions. Discussion of the ways to solve the most acute problems affecting mountainous regions with complex relief has always been on the agenda as a topical issue. The purpose of the presented work is to determine the quantitative, qualitative and thermodynamic parameters of geothermal sources in these territories, as well as the spatial structure of the foci of formation of their migration routes. Conducting a comprehensive assessment of the biodiversity of deforested mountainous regions substantiates the need to ensure the protection of these unique ecosystems. The issue of determining the direction of the integrated use of geothermal resources is studied not only by its structure and characteristics, but also by the level of development of complex technological processes for the extraction and processing of hydromineral raw materials and the technology of thermal energy processes. Using a number of analytical research methods (hydrogeological, geochemical, geophysical, isotope, computer (mathematical) modeling and others) to solve these problems, we determine the foci of formation of reservoir conditions in individual horizons, migration routes, as well as quantitative and qualitative parameters of thermal waters. The following issues were studied: hydrogeological research methods will help to identify the development zone of the intensive circulation aquifer (active water exchange) and the base of the development zone of the deep underground flow aquifer (impeded exchange) in the underground hydrosphere zones, and to assess their hydrodynamic and hydrothermal conditions and parameters. Based on the data from drilled exploratory oil wells, the conditions for the formation of thermal water layers in various hydrogeological structures will be determined; hydrochemical research methods will be aimed at assessing the macro- and microcomponent composition and radiation background of thermal waters at various intervals of migration routes by determining various indicators at different depths of their formation (based on the petrochemical structure of the geological part); isotopic studies of the gas composition of thermal waters will help to identify their genesis and use them as a marker when determining the points of formation; computer modeling of the underground hydrosphere of a representative object was carried out using mathematical programs.

Fabrication of CO2-Saturated Nanofluids with Optimized Interfacial Properties for Carbon Capture, Utilization, and Storage

Summary In the pursuit of carbon neutrality and mitigation of carbon dioxide (CO2) emissions, researchers have been exploring various approaches to integrate carbon capture, utilization, and storage (CCUS) with enhanced oil recovery (EOR) techniques. CO2 injection has been identified as a promising method to reduce crude oil viscosity and enhance its mobility within the reservoir. However, the high mobility of CO2 can lead to gas fingering, causing channeling and reducing the sweep efficiency. While CO2 foam has been considered to improve conformance during CO2 flooding, its longevity is negatively affected by harsh reservoir conditions. Polymers, which could be used as CO2 foam stabilizers, are limited by high injection pressures and CO2-induced viscosity reduction, hindering their widespread industrial application. Nanofluids, which are colloidal suspensions of nanoparticles in a base fluid, have emerged as a potential solution for various petroleum industry applications, including wettability alteration, interfacial tension (IFT) reduction, and sweep efficiency improvement. Functionalized nanoparticles can enhance oil recovery by intensifying interactions with oil, particularly through CO2 adsorption, which promises to be a more desirable solution for CO2-EOR. Inspired by drug delivery in nanomedicine, this study proposes a novel approach where CO2 is loaded onto the amine groups of nanoparticles for controlled and slow release in target zones, aiming to mitigate CO2 channeling and maximize CO2 utilization, thereby enhancing the CO2-EOR performance. Amine-functionalized nanoparticles were prepared by 3-aminopropyltriethoxysilane (KH550), grafted and polyethylenimine (PEI)-coated to load CO2 within their structure, and the interfacial characteristics between crude oil and the nanofluid were extensively examined. It was revealed that amine-functionalized nanoparticles exhibited a decent CO2 adsorption capacity of 3.3 mmol/g. Following the absorption of CO2 at 25°C by the nanofluid, the ζ-potential of the CO2-saturated nanofluid increased to +38.21 mV, which significantly enhanced the nanofluid stability. The CO2-saturated nanofluid considerably reduced the IFT between crude oil and the nanofluid from 34.78 mN/m to 7.82 mN/m at 80°C, 12 MPa. After 36 hours of soaking at 80°C, the contact angle on the oil-wet sandstone surface decreased from 121.39° to 57.95°. Furthermore, it was revealed that a distinct phase rich in heteroatoms appeared at the nanofluid-crude oil interface. Fourier-transform ion cyclotron resonance (FT-ICR) mass spectrometry (MS) demonstrated that the microdispersed phase was predominantly composed of acidic heteroatom compounds, mainly in the form of CxHyOz and CxHyOzSn, highlighting the potential of amine-modified nanoparticles to alter interfacial properties. These compounds played a crucial role in the formation and stabilization of emulsions, as well as in the optimization of oil-water interfacial properties. Ultimately, in the coreflooding experiments, the injection of nanofluid recovered an additional 15.33% of the crude oil following waterflooding.

A successful case study of using HCl and viscoelastic diverting acid systems for carbonate matrix acidizing in an oil well with optimized predictive model

The oil and gas industry is continuously seeking advanced methods to optimize reservoir productivity. Among the techniques employed, matrix acidizing, particularly using Viscoelastic Diverting Acid (VDA), has shown significant promise in enhancing permeability and improving well performance. However, the absence of standardized formulations for VDA requires a careful evaluation of commercial additives to ensure their reliability and effectiveness in diverse reservoir conditions. This article presents a comprehensive case study that examining the application of hydrochloric acid (HCl) and VDA systems in a low-permeability carbonate reservoir situated in southern Iran. The study integrates design of experiments (DOE) and multi-objective optimization techniques to assess the impact of various operational parameters on acidizing performance. The research focused on high-temperature formations, employing multi-stage acid injections to evaluate the effectiveness of the acid treatments. The use of DoE and response surface methodology (RSM) provided a structured approach for optimizing key parameters to enhance treatment outcomes. The results of this study demonstrated a substantial increase in both oil production and well pressure following the acidizing process. Specifically, oil production improved by 80%, and well pressure increased by 73%, underscoring the effectiveness of the acid treatment in stimulating the reservoir. The VDA system, combined with the bullheading injection technique, facilitated superior acid placement and distribution within the reservoir, enhancing the overall acidizing efficiency. Furthermore, the optimization of operational parameters such as skin factor and maximum invasion depth through the use of RSM allowed for a significant refinement of the acidizing process. The developed models, with correlation coefficients exceeding 0.96, further validated the accuracy of the optimization process and provided valuable insights into the critical factors influencing acidizing performance. Additionally, the refined acidizing program minimized operational uncertainties, leading to improved treatment efficiency and more consistent results in challenging high-temperature formations.

Accounting for melting properties in the multi-solid paraffin prediction model for analyzing well production at fields in the Republic of Kazakhstan

The deposition of paraffin on pipeline walls is a serious flow issue. leading to a reduction in oil production due to the decreased flow cross-sectional area. and in severe cases. to complete blockage. This problem also results in increased energy consumption and causes failure of surface equipment due to paraffin plugs. Traditional methods predict paraffin crystallization temperature by considering the impact of temperature on the solubility parameters of individual components in both liquid and solid phases as well as their molar volumes. The goal of this study is to improve the prediction of paraffin deposition in Kazakhstan crude oil by incorporating an evaluation of melting properties into the multi-solid (MS) body prediction model. The process of calculating and adjusting melting properties to enhance the accuracy of the MS model is described in detail. This approach helps to overcome the limitations faced by most existing models when adapting to different types of crude oil. In this study, the focus is on optimizing the multi-solid (MS) body prediction model for paraffin deposition by integrating the melting properties of crude oil components. The improvement of the MS model is crucial because paraffin deposition is a significant issue in Kazakhstan's oil fields, where the wide range of reservoir conditions can cause standard prediction models to fall short. By enhancing the accuracy of melting point calculations, the updated model can better predict the onset of paraffin crystallization and its deposition tendencies under varying pressure and temperature conditions. Keywords: melting properties; multi solid solution; petroleum; solid solution; paraffin deposition

Application of aluminum nanoparticles in reagents for oil viscosity reduction

The problem of extracting hard-to-recover reserves, which belong to the category of heavy and highly bound oil, is one of the most pressing oil industries. Many mining companies actively use physical and chemical methods to solve this problem. The use of nanotechnology in physical and chemical methods for increasing oil production is a relatively new area. Nanoparticles easily enter the regime, their size allows them to spread more easily in porous media without reducing permeability. The main goal of the research was to reduce oil viscosity and achieve increased production. In order to increase oil recovery, the proposed method for reducing oil viscosity in reservoir conditions based on treating the bottomhole zone of production wells with a solution of caustic soda and nanoparticles affects the dimension of 40-60 nm (concentrations of 1, 0.1 and 0.01 %). The nanoparticles were obtained using an electrical conductor method and studied by transmission electron microscopy. Determination of surface tension using a DSA30 device (Kruss, Germany) using the pendant drop (PD) method. The samples for testing were oil samples, visible wells No. 222761 Binagadi-North, No. 220051 Fatmai area and No. 221937 Kirmaki area, trading company "Binagadi Oil". Based on experimental data, it was found that the proposed composition reduces the viscosity of oil by several times in all three experimental samples, nanoparticles have a positive effect on reducing viscosity, the greatest effect was noted with 0.01% nanoparticles, this composition can be used to increase the production of high-viscosity oils. Keywords: nanotechnology; metal nanoparticles; enhanced oil recovery; reduce oil viscosity.

Enhancing sand control in loose reservoirs: nanofluid application

This paper introduces a novel epoxy-based nanofluid for sand control in loose reservoirs prone to sand production issues. The nanofluid combines epoxy resin with carbon nitride nanoparticles and a gas generating agent to enhance both compressive strength and permeability. Experimental studies demonstrate significant improvements in compressive strength and permeability, indicating the potential effectiveness of the nanofluid in consolidating sand in oil and gas reservoirs. Sandpack flooding experiments under reservoir conditions reveal promising results, suggesting the nanofluid's suitability for various permeability characteristics. These findings propose the epoxy/g-C₃N₄ nanofluid as a promising solution for sand consolidation, warranting further research and field testing for practical application in reservoir engineering. Keywords: sand control; epoxy nanofluid; chemical sand consolidation; graphitic carbon nitride; compressive strength enhancement; permeability control.

Enhancing Computing Capacity via Reconfigurable MoS2‐Based Artificial Synapse with Dual Feature Strategy for Wide Reservoir Computing

AbstractReservoir computing (RC) has garnered considerable interest owing to its uncomplicated network structure and minimal training costs. Nevertheless, the computing capacity of RC systems is limited by the material‐dependent physical dynamics of reservoir devices. In this study, an efficient neuromorphic reservoir device with adjustable reservoir states, achieved through the development of an electrically tunable three‐terminal charge trap memory, is introduced. This device utilizes molybdenum disulfide (MoS2) as the channel material and a perhydropolysilazane‐based charge trap layer. Notably, the absence of a tunneling layer in the device structure enables dynamic resistive switching, characterized by outstanding endurance and an excellent memory window. Furthermore, by implementing a simple input decay and refresh scheme, a reconfigurable neuromorphic device capable of multiple feature extraction and functioning as an artificial synapse is developed. The device's efficacy is validated through device‐to‐system‐level simulations within a hardware‐based wide RC (WRC) system, resulting in an improved recognition rate in the MNIST hand‐written digit recognition task from 87.6% to 91.0%, a testament to the enhanced computing capacity. This strategic approach advances the development of hardware‐based WRC systems, marking a significant step toward energy‐efficient reservoir computing.

Investigating the Adsorption Behavior of Zwitterionic Surfactants on Middle Bakken Minerals

Zwitterionic surfactants are a promising option for application in harsh reservoir conditions due to their exceptional stability, compatibility, and interfacial activity. However, surfactant adsorption remains a significant concern. This study investigates the adsorption behavior of zwitterionic surfactants was studied on complex Middle Bakken minerals under high-salinity (total dissolved solids (TDS) = 29 wt%) and high-temperature (90 °C) conditions using the spectrophotometric method. The adsorbents were prepared by grinding Bakken core plugs using a ball mill and sifting them through 40 μm mesh sieves to ensure uniform particle size distribution. The results showed that the Langmuir adsorption model accurately describes the adsorption isotherms of zwitterionic surfactants. The impact of salinity on the zwitterionic surfactants adsorption varied depending on the presence of acidic and/or basic groups in the surfactants. Using Bakken formation brine instead of brine solutions with 2% TDS resulted in a decrease in adsorption of approximately 1.06 ± 0.02 mg/g for CG3 and 0.3 ± 0.04 mg/g for both CD2 and ME1. This reduction was observed in betaine-type zwitterionic surfactants with −COO− functional groups that may gain protons, compared to their adsorption capacities in the 2% TDS brine (2.35 mg/g, 2.1 mg/g, and 1.89 mg/g, respectively). This study provides critical insights into the behavior of interfacial tension (IFT) between crude oil and surfactant solutions, which is vital for optimizing enhanced oil recovery (EOR) processes. The findings underline the importance of surfactant concentration and adsorption characteristics, offering valuable guidelines for practical applications in petroleum reservoir management. Overall, zwitterionic surfactants exhibit higher adsorption on Bakken minerals regardless of the salinity condition.

Production Performance Analysis to Mature Field Development Plan

The research focuses on evaluating the production performance of three oil wells-Well F55A MB, Well Hovea 13 ST1, and Well Pedirka-1-using Inflow Performance Relationship (IPR) and Vertical Lift Performance (VLP) analysis to determine optimal artificial lift methods for each case. The study explores critical production parameters such as reservoir pressure, temperature, and gas-to-oil ratio (GOR) while employing decision tree methodologies to select suitable artificial lift systems. For Well Hovea 13 ST1 and Well Pedirka-1, gas lift installations significantly enhanced oil recovery rates by optimizing injection pressures and valve placements, achieving production gains of 694 and 300 barrels per day, respectively. In contrast, Well F55A MB, characterized by high water cut and lower reservoir temperatures, was deemed unsuitable for artificial lift based on the decision tree analysis, with a stable production of 2832 stb/d. This work highlights the importance of tailored artificial lift strategies for maximizing oil recovery and improving well performance in diverse reservoir conditions.