Mobile Oil Research Articles

Quantitative characterization of crude oil mobilization in microscopic pores during forward and reverse flooding in tight sandstone reservoirs using various fracturing fluid systems

In the transition from conventional to unconventional oil and gas exploration, the focus on tight sandstone reservoirs has grown due to their complex microscopic pore structures, narrow pore throats, and high capillary pressures. These characteristics often lead to the retention of fracturing fluids post-fracturing, hindering fluid recovery and reducing crude oil extraction efficiency. To address these issues, this study employed a combination of microscopic displacement experiments and nuclear magnetic resonance (NMR) analyses to investigate oil displacement mechanisms at the microscale in tight sandstone reservoirs. The experimental setup involved testing three core samples using distinct fracturing fluid systems: a guar gum-based system (System I), an EM30+ + guar gum water-based system (System II), and a CNI (Carbon Nanotechnologies Inc) nano variable-viscosity slick water-based system (System III). The study aimed to assess the impact of these different fracturing fluid systems on oil displacement efficiency in both forward and reverse directions. Results revealed that forward oil displacement efficiencies for Systems I to III were 26.86%, 33.3%, and 33.43%, respectively. In contrast, reverse displacement efficiencies were slightly higher at 28.9%, 37.5%, and 38.34%. Overall, Systems II and III outperformed System I in terms of oil displacement efficiency. The study also found that in cores with large pores, forward displacement predominantly mobilized crude oil, while reverse displacement was more effective in smaller pores. This trend was consistent in cores exhibiting bimodal pore distributions. However, in unimodal cores, small pores were significantly impacted in both directions. Notably, System III demonstrated a remarkable efficiency in mobilizing crude oil within smaller pores.

Preparation of Pickering emulsion stabilized by novel amphiphilic silicon quantum dots and its application in enhanced oil recovery

In this article, a three-step method was suggested for synthesizing amphiphilic silicon quantum dots (A-SiQDs) through a simple and mild reaction process. The A-SiQDs were used to stabilize the Pickering emulsion. The A-SiQDs were characterized by high-resolution transmission electron microscopy (HRTEM), Fourier transform infrared spectrometer (FTIR), X-ray photoelectron spectrometer (XPS), and dynamic light scattering (DLS). The A-SiQDs had high interfacial modulus and can reduce the interfacial tension from 20.69 mN·m−1 to 1.97 mN·m−1. Moreover, A-SiQDs had the ability to alter the wettability of the core from oil-wet to water-wet. The Pickering emulsion stabilized by 0.2 wt% A-SiQDs can still maintain more than 70% of the emulsion index (EI) after 30 days. And the Pickering emulsion exhibited excellent stability even at 90 °C. It was found that the addition of salts can improve the stability of emulsion. The network structure formed by the hydrogen bonds and hydrophobic interactions between A-SiQDs around the emulsion droplets results in enhancing shear resistance and stability of the Pickering emulsion. The Pickering emulsion flooding and microscopic visualization displacement results indicated that the Pickering emulsion can increase oil recovery by 17.9% through reducing the water–oil mobility ratio and expanding the swept area. This paper proposes a simple and innovative method for the synthesis of A-SiQDs and also provides a new nanoparticle with better performance for stabilizing Pickering emulsion.

Numerical Investigation on Alkaline-Surfactant-Polymer Alternating CO2 Flooding

For over four decades, carbon dioxide (CO2) has been instrumental in enhancing oil extraction through advanced recovery techniques. One such method, water alternating gas (WAG) injection, while effective, grapples with limitations like gas channeling and gravity segregation. To tackle the aforementioned issues, this paper proposes an upgrade coupling method named alkaline-surfactant-polymer alternating gas (ASPAG). ASP flooding and CO2 are injected alternately into the reservoir to enhance the recovery of the WAG process. The uniqueness of this method lies in the fact that polymers could help profile modification, CO2 would miscible mix with oil, and alkaline surfactant would reduce oil–water interfacial tension (IFT). To analyze the feasibility of ASPAG, a couples model considering both gas flooding and ASP flooding processes is established by using the CMG-STARS (Version 2021) to study the performance of ASPAG and compare the recovery among ASPAG, WAG, and ASP flooding. Our research delved into the ASPAG’s adaptability across reservoirs varying in average permeability, interlayer heterogeneity, formation rhythmicity, and fluid properties. Key findings include that ASPAG surpasses the conventional WAG in sweep and displacement efficiency, elevating oil recovery by 12–17%, and in comparison to ASP, ASPAG bolsters displacement efficiency, leading to a 9–11% increase in oil recovery. The primary flooding mechanism of ASPAG stems from the ASP slug’s ability to diminish the interfacial tension, enhancing the oil and water mobility ratio, which is particularly efficient in medium-high permeability layers. Through sensitivity analysis, ASPAG is best suited for mid-high-permeability reservoirs characterized by low crude oil viscosity and a composite reverse sedimentary rhythm. This study offers invaluable insights into the underlying mechanisms and critical parameters that influence the alkaline-surfactant-polymer alternating gas method’s success for enhanced oil recovery. Furthermore, it unveils an innovative strategy to boost oil recovery in medium-to-high-permeability reservoirs.

Pore throat distributions and movable fluid occurrences in different diagenetic facies of tight sandstone reservoirs in the Triassic Chang 6 reservoirs, Wuqi Area, Ordos Basin, China

The 6th member of the Triassic Yanchang Formation, hereafter referred to as Chang 6 reservoir, in the Wuqi area of the Ordos Basin presents formidable obstacles for efficient tight oil development. This reservoir is known for its tight lithology, strong heterogeneity, inadequate oil saturation, and abnormally low reservoir pressure, which collectively contribute to the highly differentiated mobility of tight oil within the formation. To overcome these challenges, a comprehensive understanding of the factors influencing oil mobility is essential. This study investigates the occurrence characteristics of movable fluids in different diagenetic facies and the corresponding influential factors by employing various microscopic experiments, including high-pressure mercury intrusion, constant-rate mercury intrusion, nuclear magnetic resonance test, scanning electron microscopy, pore-casted thin section analysis, and X-ray diffraction measurement. There is a weaker correlation between the pore-throat radius ratio and the movable fluid saturation in reservoirs of various diagenetic facies (R2 = 0.6104), whereas there is a stronger correlation between movable fluid saturation and throat radius (R2 = 0.9415). Among the seven types of diagenetic facies, chlorite membrane cementation-intergranular pore facies (Facies I) and chlorite and illite membrane cementation-intergranular pore facies (Facies II) have the best-developed throats and the highest coordination number. Illite cementation-intergranular pore facies (Facies III) and illite and chlorite membrane cementation-dissolution facies (Facies IV) demonstrate smaller pore-throat radii and moderate to poor reservoir connectivity. The other three facies, namely illite cementation-dissolution facies (Facies V), illite cementation facies (Facies VI), and carbonate tight cementation facies (Facies VII) exhibit underdeveloped pore structures and lower recovery rates. Pore-throat radius emerges as the principal factor influencing reservoir permeability and storage capacity. The distribution of favorable diagenetic facies is influenced by depositional environments, diagenetic processes, and microscopic pore-throat characteristics. This study significantly enhances our understanding of the differential occurrence characteristics of fluids in different diagenetic facies in the Chang 6 reservoir, providing valuable insights for future exploration and production endeavors aimed at optimizing oil recovery in tight sandstone reservoirs.

Two-dimensional spectrum characteristics and oil movability study of the shale oil reservoir

Shale oil is mainly stored in the nano–micro-pores of shale in the form of adsorption or in a free state. Among them, only free-state oil is the main contributor to shale oil production under natural elastic energy. Therefore, it is crucial to evaluate the movability of crude oil effectively. In this paper, focusing on the Jurassic shale oil reservoir core in the middle-eastern Sichuan region of China, low-field nuclear magnetic resonance (NMR) technology is used to analyze the basic characteristics of shale oil core samples. Experiments on the low-field NMR one-dimensional and two-dimensional spectrum characteristics of the original core, heat-treated core, and thermogravimetric-treated shale core are carried out. The effects of the TG-MS method, T2 method, and the volatilization of light oil components on the movability of shale oil reservoirs are analyzed, and the movability characteristics of shale oil reservoirs in the middle-eastern Sichuan region are preliminarily clarified. The results show that under thermal treatment, the distribution range of the two-dimensional spectrum of the core oil occurrence area is significantly reduced, and the T1 and T2 distribution ranges are reduced by 10.9% and 60.7%, respectively. According to the TG-MS method, the mobile oil, bound oil, and adsorbed oil account for 74.7%, 8.1%, and 17.2%, respectively. The quantitative calculation of movable oil saturation by NMR combined with heat treatment is 65.6%, which is lower than that calculated using the thermogravimetric method. In order to calculate the movability more accurately, the scale effect between different samples should be considered. This study could provide a theoretical basis for the subsequent shale oil development program.

Laboratory Investigation on Permeability Change and Economic Analysis Using Some Selected Nanoparticles for Enhanced Oil Recovery

Enhanced oil recovery using nanoparticles is an emerging technique that can potentially alter permeability and wettability of porous media for improved oil mobilization. This study experimentally investigates the permeability alteration caused by three commonly used nanoparticle types – copper (ii) oxide, zinc oxide and silicon oxide. Core flooding experiments were conducted on reservoir rock samples before and after treatment with nanoparticle dispersions. Results show decrease in permeability by 35% for copper (ii) oxide, 30% for zinc oxide and 10% silicon oxide respectively. Pore-scale analysis indicates that permeability change occurs through mechanisms like pore throat blocking/wettability alteration. Nanoparticle concentration is also found to influence the permeability variation, with optimal dosage. Among the systems tested, Silicon oxide is the most effective formulation for enhancing oil recovery applications based on its ability to recover oil with minimal alteration to formation permeability. From the result, Silicon oxide had a cumulative recovery of 17ml, 18.0ml and 18.5ml thereby generating a percentage recovery of 73.91%, 78.26% and 80.43% while Zinc oxide had a cumulative recovery of 15.5ml, 18.0ml and 16.5ml thereby generating a percentage recovery of 77.50%, 78.26% and 71.74ml%, lastly Copper (ii) oxide had a cumulative recovery of 16.5ml, 17.0 and 16.0 generating a percentage recovery of 75%, 73.91% and 72.72% respectively with a concentration of 0.1%, 0.3%, and 0.5%. This study demonstrates the potential of Silicon oxide nanoparticles for enhanced oil recovery through permeability manipulation in porous media, however, the economic analysis shows that it’s quite expensive due to its cost of production and won’t be ideal for use. Hence Zinc oxide which also has a high volume of oil recovery, and less production cost can be used.

Research on the Influence of Sand-Mud Interlayer Properties on the Expansion of SAGD Steam Chamber

Summary Thermal recovery techniques serve as the primary approach for developing heavy oil due to its high viscosity and poor flowability. In this study, we established a high-temperature and high-pressure 3D physical experimental and numerical model based on the unique reservoir characteristics of the sand-mud interlayer in the Long Lake oil sands of Canada, using similarity criteria. Physical and numerical experiments employing steam-assisted gravity drainage (SAGD) were conducted to investigate the impact of sand-mud interlayer properties on the expansion limit of steam chambers during SAGD development. The results indicate that the expansion mode and limit of the steam chamber play a decisive role in heavy oil mobilization. Notably, heat loss during steam chamber expansion and the flow resistance caused by the interlayer are critical factors influencing the SAGD process. The presence of the interlayer extends the mobilization range in the lower portion of the reservoir, but it also limits the upward expansion of the steam chamber, resulting in a reduced mobilization range above the interlayer. Moreover, the steam chamber above the interlayer exhibits a distinct expansion pattern, featuring concave sides and a convex middle, resembling a “positive triangle.” Furthermore, the properties of the sand-mud interlayer and production parameters significantly affect the expansion limit of the steam chamber. Permeability and position exert a substantial impact on recovery, whereas thickness has a minor influence. Specifically, at an injection rate of 20 mL·min–1, steam quality of approximately 0.7, and a production/injection ratio of approximately 1.0, the steam chamber can successfully penetrate interlayers with a thickness of either 3.5 m and a permeability of 100×10−3 μm2 or 4.5 m and a permeability of 200×10−3 μm2.

ОЦЕНКА ВОЗМОЖНОСТИ ЭСКАЛАЦИИ ПОЖАРА ПРИ ХРАНЕНИИ МОТОРНЫХ ТОПЛИВ В ПОЛИМЕРНЫХ ЭЛАСТИЧНЫХ РЕЗЕРВУАРАХ

Due to the increase in oil production and production of petroleum products, as well as their transportation and storage, the range and sizes of reservoirs are increasing. For this purpose, polymer tanks are widely used at Russian enterprises of the fuel and energy complex, including mobile tank farmsand oil depots for the operational storage of oil and petroleum products. However, the polymer materials from which the tanks are made are flammable, which increases their fire hazard level. An assessment of the possibility of fire escalation has been carried out using the example of an oil depot model for storing motor fuels in polymer elastic tanks. The results 
 of calculating the dangerous factors of a spill fire during depressurization of polymer elastic tanks with gasoline and diesel fuel, as well as a graph of the dependence of the intensity of thermal radiation during the ignition of these tanks, are presented in tabular form, and an event tree is constructed. The parameters characterizing the possible escalation of a fire at a motor fuel storage site under quasi-stationary conditions have been determined.
 A methodology is proposed that allows assessing the possibility of realizing the escalating nature of a fire at facilities for storing and handling motor fuels in polymer elastic tanks, and recommendations are also given to prevent the progressive nature of the development of negative events and reduce damage in case of fire.

Modeling of Chemical Tracers for Two-Phase Flow in Advective-Dominated Porous Media at Core Scale

Summary Chemical tracer modeling in porous media plays a key role in subsurface applications including oil recovery, aquifer remediation, and geothermal energy production. In oil reservoirs, chemical tracers are critical to quantifying the remaining oil saturation in porous media after displacing processes, enabling the correct evaluation of the sweep efficiency of recovery methods at the field scale. Even though the transport of solutes under single-phase flow has been modeled extensively with numerous solutions, there are no existing mathematical approaches to examine the displacement of solutes in two-phase flow conditions. Therefore, we present in this research work the first analytical solutions derived to model the transport of ideal and partitioning tracers in porous media with mobile water and oil phases. The models presented are derived from the classic study of fluid displacement by viscous forces and the analysis of dynamic phase distribution in porous media, where key transformation variables are introduced to simplify the nonlinear advection-dispersion equation (ADE) into a conventional partial differential expression. In our derivation process, it is recognized that the dispersion effect can be superimposed onto an ideal concentration front via a singular perturbation expansion, resulting in practical solutions that do not require complex numerical calculations or inversion methods. The solutions derived are verified with numerical simulations and validated with experimental data under different flow conditions for the transport of ideal and partitioning tracers, demonstrating that the complex mechanisms of hydrodynamic dispersion, partitioning, and adsorption are accurately modeled under two-phase flow. Thus, our solutions can be used to rapidly evaluate tracer transport under the existing flow conditions in porous media, significantly reducing the number of experiments and simulations to characterize and select the correct tracer to be used in field applications.

Surfactant-Enhanced Assisted Spontaneous Imbibition for Enhancing Oil Recovery in Tight Oil Reservoirs: Experimental Investigation of Surfactant Types, Concentrations, and Temperature Impact

Surfactant-assisted spontaneous imbibition is an important mechanism in enhanced oil recovery by capillary pressure in low permeability and tight oil reservoirs. Though many experiments have been conducted to study the mechanism of enhanced oil recovery by surfactant-assisted spontaneous imbibition, the effects of surfactant type, concentration, and temperature have not been well studied. Using tight sandstone outcrop core samples with similar permeability and porosity, this paper experimentally studies surfactant-assisted spontaneous imbibition using three different surfactant types, i.e., sodium dodecylbenzene sulfonate (SDBS), cocamidopropyl betaine (CAB), and C12–14 fatty alcohol glycoside (APG). In addition to the type of surfactant, the effect of the surfactant concentration and the temperature is also investigated. The study results show that the ultimate oil recovery of spontaneous imbibition with formation water and denoised water is about 10%. Surfactant can significantly improve the oil recovery of spontaneous imbibition by reducing the interfacial tension between oil and water, emulsifying crude oil and improving oil mobility. APG showed better performance compared to SDBS and CAB, with a maximum oil recovery factor of 36.19% achieved with formation water containing 0.05% APG surfactant. Lower concentrations (0.05% APG) in the formation water resulted in a higher oil recovery factor compared to 0.1% APG. Increasing temperature also improves oil recovery by reducing oil viscosity. This empirical study contributes to a better understanding of the mechanism of surfactant-assisted spontaneous imbibition and enhanced oil recovery in tight oil reservoirs.

Study on the mobility control ability of a quaternary ammonium salt active polymer for oil flooding

Mobility control ability is an important property of polymer used in oil displacement. This work initially investigates the temperature and salt resistance, steady-state rheology, dynamic viscoelasticity, and long-term stability of a quaternary ammonium salt active polymer (AM/AMPS/DMCA). Subsequently, an examination was conducted to evaluate the static adsorption ability of AM/AMPS/DMCA on the surface of quartz sand, as well as the dynamic retention property within cores. Finally, the mobility control ability and oil displacement capacity of AM/AMPS/DMCA under various injection conditions was investigated in this study. The findings illuminate the superior attributes of AM/AMPS/DMCA, including its remarkable temperature and salt endurance, alongside its long-term stability, presenting a significant advancement over traditional binary polymers like AM/AMPS. Notably, AM/AMPS/DMCA exhibits a predominantly elastic modulus, which enhances its movement and deformation inside porous media. Furthermore, it has been shown that the resistance factor and residual resistance factor achieved by the 2000 mg/L AM/AMPS/DMCA solution in the core of 96.6 mD were 184.50 and 46.95, respectively. The enhanced oil recovery (EOR) value of 0.6 PV of AM/AMPS/DMCA achieved 30.48% in the core of 588.8 mD. This study not only demonstrates the capability of AM/AMPS/DMCA in EOR but also facilitates the understanding of the mobility control mechanism of polymers in porous media, offering valuable empirical guidance for the field application of polymers.

Alternative Methods of thermal Oil Recovery: A Review

Oil production from fields with hard-to-recover reserves always remains a challenge for the oil and gas industry, mainly due to one special factor – the high viscosity of oil, which implies low mobility of oil in a porous medium. Over time, traditional methods of increasing oil recovery become less effective due to a decrease in readily available oil reserves and the complexity of geological conditions for field development. In this regard, the need to use innovative methods to increase oil recovery is becoming more urgent. In recent decades, research in this area has shown significant progress, various methods have been introduced to reduce the viscosity of oil. One of the most effective and actively developing approaches in this area is thermal methods of enhanced oil recovery. They are based on the injection of thermal energy into the reservoir in order to reduce the viscosity of oil and, consequently, increase mobility, which in turn will greatly facilitate the displacement of oil from the rock to the surface.
 Despite certain successes achieved in the use of various methods of increasing oil recovery in the production of heavy oil, the problem of finding alternative methods remains relevant.
 This article presents the review of alternative methods of enhanced oil recovery, including principle of operation of electromagnetic heating of the reservoir, the influence and effectiveness of radio waves and microwave frequencies on the reservoir and the properties of oil, ultrasonic exposure, advantages and disadvantages of alternative methods, comparing them with traditional methods, analyzing the productivity of fields where alternative methods of enhanced oil recovery were used.

Influence of viscosity ratio on enhanced oil recovery performance of anti-hydrolyzed polymer for high-temperature and high-salinity reservoir

The viscosity ratio of polymer and oil is a crucial factor for polymer flooding, which can affect the water–oil mobility ratio and oil recovery. However, for high-temperature and high-salinity reservoirs, the reasonable viscosity ratio limit of polymer flooding under the condition of medium–high permeability and low oil viscosity is not clear. Thus, the heterogeneous sand-pack flooding experiments were carried out to analyze the influence of polymer–oil viscosity ratio on the enhanced oil recovery (EOR) performance of anti-hydrolyzed polymer to establish a reasonable viscosity ratio limit. Then the three-dimensional heterogeneous model flooding experiments were performed to clarify the mechanism. The results showed that when the permeability ratio was the same, as the viscosity ratio increased from 0.15 to 2.0, the incremental oil recovery increased from 3.2% to 27.2%. When the viscosity ratio was the same, the incremental oil recovery decreased with the increase in the permeability ratio. The reasonable viscosity ratio ranges from 1.0 to 1.5. For three-dimensional heterogeneous model flooding experiments, as the polymer–oil viscosity ratio increased from 0.45 to 1.0, the swept area of high and low permeability area was expanded and the oil saturation near the injection well in the mainstream channel was greatly reduced. Moreover, when the polymer–oil viscosity ratio was 1, the difference in the width of the mainstream channels between high and low permeability layers in the saturation field decreased, and the degree of utilization in low permeability layers increased significantly. As the polymer–oil viscosity ratio increased from 0.45 to 1.0, the incremental oil recovery increased from 16.2% to 24%.

Comparison Different Techniques of Optimum Location for Infill Well Drilling

Increasing oil production from a reservoir can be achieved by decreasing the distance between the injector and the producer through a process known as infill drilling, which involves a pattern water flood. The main objective of this study is to provide a comprehensive overview of the optimal infill well location and the research and applications available to enhance the oil recovery factor, leading to increased economic profits. one effective empirical approach used in this study is based on decline curve analysis, which analyzes the production history of the well to determine the final economic recovery. Additionally, a numerical method that combines numerical simulation and optimization techniques has been proven to be successful in determining optimal infill drilling locations. The research results show that the volumetric computation of oil in place is a useful method for estimating the number of infill wells needed, but it does not consider heterogeneity and continuity. On the other hand, the numerical simulation and optimization techniques can quantify the remaining mobile oil post-infill drilling and establish optimal pattern configurations for maximum recovery at their centers.

Analysis of the Distribution Pattern of Remaining Oil and Development Potential after Weak Gel Flooding in the Offshore LD Oilfield.

The LD oilfield is one of the representative offshore oilfields. After weak gel flooding, the recovery rate is significantly improved. However, the oilfield is then in a medium- to high-water content stage, presenting a complex distribution of the remaining oil. The measures for further enhanced oil recovery (EOR) are uncertain. As a result, it is necessary to clarify the distribution pattern and development potential of the remaining oil during the high-water content period after weak gel flooding. In this study, an online nuclear magnetic resonance (NMR) oil displacement experiment and microscopic oil displacement experiment were conducted, and the mechanisms of weak gel flooding and the distribution pattern of the remaining oil were clarified in the LD oilfield. Additionally, high-multiple water flooding and numerical simulation experiments were conducted to analyze the development potential after weak gel flooding. The results show that the effect of weak gel flooding was more significant in the core of 1500 mD, with an increase in oil recovery of 9% compared to 500 mD. At a permeability of 500 mD, the degree of crude oil mobilization in micropores and small pores caused by weak gel flooding was improved by 29.64% and 23.48%, respectively, compared with water flooding. At 1500 mD, the degree of crude oil mobilization in small pores caused by weak gel flooding was increased by 37.79% compared to water flooding. After weak gel flooding, the remaining oil was primarily distributed in medium and large pores. Microscopically, the remaining oil was dominated by cluster residual oil, accounting for 16.49%, followed by columnar, membranous, and blind-end residual oil. High multiple water flooding experiments demonstrated that weak gel flooding could significantly reduce development time. The ultimate oil recovery efficiency of 500 mD and 1500 mD reached 71.85% and 80.69%, respectively. Numerical simulation results show that the ultimate oil recovery efficiency increased from 62.04% to 71.3% after weak gel flooding. This indicated that the LD oilfield still had certain development potential after weak gel flooding. The subsequent direction for enhanced oil recovery focuses mainly on mobilizing oil in medium pores or clustered remaining oil. This will play a crucial role in further exploring methods for utilizing the remaining oil and increasing the recovery rate.

Evaluation method of oil saturation index OSI for shale oil reservoir based on well logging data

Oil saturation index (OSI) serves as an important indicator for potential movable hydrocarbons evaluation of shale oil reservoirs, which is mainly obtained through rock pyrolysis experiments. A new method is proposed to evaluate the OSI of shale quantitatively by NMR logging. The OSI value can be accurately obtained through the experimental measurement of organic carbon content (TOC) and rock pyrolysis of shale samples, which can identify the development of mobile hydrocarbons. Subsequently, the mobile fluid porosity can be obtained based on NMR logging. In order to establish the relationship between OSI value and mobile fluid porosity, it is important to determine the T2 cutoff value corresponding to the mobile fluid porosity. Take shale samples from the first member of the Qingshankou Formation (“Qing 1 Member”) as an example, based on 2D NMR experimental analysis in three different states (original, dried state at 105°C, saturated kerosene), the NMR T2 cutoff value of movable fluid porosity in the shale of Qing 1 Member is clarified as 8 ms. Integrating rock pyrolysis and 2D NMR experiments, it suggests that the NMR bin porosity with T2>8 ms has a good linear relationship with the OSI value obtained by pyrolysis analysis. The NMR bin porosity with T2> 8 ms reflects the OSI value of shale effectively. The larger the NMR bin porosity with T2>8 ms, the higher the mobile oil content of shale reservoir, which is consistent with the understanding of oil-bearing large pores in the Gulong Shale. The NMR bin porosity can continuously evaluate the vertical variation of the mobile hydrocarbon content. Compared with the traditional experimental measurement of finite depth points, this method has significant advantages, and can avoid the possibility of missing potentially movable oil layers.

Combining Steam and Flue Gas as a Strategy to Support Energy Efficiency: A Comprehensive Review of the Associated Mechanisms.

Conventional steam injection projects have long been an iconic process in the development of heavy oil reserves; nevertheless, they face significant challenges in terms of energy efficiency, environmental compliance, and economic viability. Factors such as oil price fluctuations, the imperative for an energy transition, and the push to reduce carbon footprints are hindering new or ongoing implementations of traditional steam injection technologies. In response to these challenges, hybrid methods, such as the combination of steam and flue gas, are emerging as an opportunity to optimize thermal processes to improve oil recovery, energy efficiency, and environmental sustainability and extend reservoir productivity life. Steam injection enhances oil recovery by reducing the viscosity of crude oil, improving oil mobility and facilitating its extraction. The utilization of flue gas in steam injection processes has a significant impact on oil recovery and energy efficiency, leveraging industrial byproducts. This not only lowers operating costs but also reduces environmental emissions, aligned with energy transition trends. Incorporating the flue gas into a steam-based process in heavy oil reservoirs has emerged as a promising thermally enhanced oil recovery strategy. This work presents a comprehensive review based on experimental, numerical, and field studies of hybrid steam and flue gas technology as an EOR process. The main recovery mechanisms associated with the process are analyzed. In addition, the laboratory equipment required for experimental evaluations is presented, and reservoir modeling, kinetic and compositional effects on reservoir fluids, and the reduction in heat losses in the steam injection process are discussed. Furthermore, field implementations are reviewed to evaluate lessons learned and experiences on an operative scale. The combination of steam and flue gas represents an opportunity for carbon utilization and geological carbon sequestration. This dual functionality underscores its potential to enhance oil recovery and address carbon-related environmental concerns.

Experimental Study on Improving Oil Recovery Mechanism of Injection–Production Coupling in Complex Fault-Block Reservoirs

In order to improve the effect of injection–production coupling development to improve crude oil recovery in complex fault-block reservoirs, we carried out a physical simulation experiment based on a sandpack model of transforming water-driven development into injection–production coupling development and quantitatively evaluated the influence of rounds of injection pressure coupling on the crude oil mobilization in reservoirs with different permeability levels and on oil recovery. Meanwhile, the characteristics of residual oil were studied via a numerical simulation method. The mechanism of increased oil production via injection–production coupling development was revealed by analyzing the water and oil contents, formation pressure, and streamline fields through the establishment of mechanism models. The results of the physical experiment show that injection–production coupling can improve the recovery effect of medium- and low-permeability reservoirs by 55.66%. With an increase in the injection pressure, the oil recovery percentage of the low-permeability sandpack model at 20 MPa is 100%, and this study finds that injection–production coupling is the main way to develop the recoverable oil in a low-permeability reservoir. The numerical simulation results show that among the four remaining oil distribution types (interwell-enriched, low-permeability zone-enriched, well network imperfection, and mismatch between injection and production), the interwell-enriched type of the remaining oil reserves accounts for the highest proportion (48.52%). The simulation results of the mechanism model show that water-driven development easily leads to streamline solidification, resulting in ineffective circulation of the injected water. Compared with conventional water-driven development, the pressure propagation range is significantly increased in injection–production coupling development. The reservoir streamline distribution is more continuous and uniform, and the flooding wave is wider in volume and range. This research provides a theoretical basis for the injection–production coupling technology policy in complex fault-block reservoirs.

Investigation of Guar Gum and Xanthan Gum Influence on Essential Thyme Oil Emulsion Properties and Encapsulation Release Using Modeling Tools.

This study explores the influence of hydrocolloid interactions between Guar Gum (GG) and Xanthan Gum (XG) on the stability and release dynamics of essential thyme oil emulsions. We systematically characterized six emulsions with varying GG and XG ratios, employing spray-drying techniques for the encapsulation process. The stability of the emulsions was quantitatively analyzed, revealing a marked decrease in stability rates correlated with higher initial emulsion activity (zero-order kinetic constant r = -0.972). Furthermore, this study demonstrated that emulsions with carefully optimized hydrocolloid ratios could achieve high encapsulation efficiency (74%) and controlled release profiles. Kinetic modeling and diffusion analyses elucidated that increased XG concentrations tend to reduce diffusivity, thereby enhancing emulsion stability. The effective diffusivity of the thyme oil within the emulsion matrix was determined to be within a range of 0.7 to 2.4 × 10-10 m2/s, significantly influencing release kinetics. The Pearson correlation matrix underlined a substantial negative association between emulsion activity and effective diffusivity (r = -0.740), indicating that denser hydrocolloid networks impede oil mobility. The findings conclusively establish that the interplay of GG and XG concentrations is pivotal in dictating the emulsion's physicochemical properties, with denser networks formed by higher XG content leading to slower oil release rates and enhanced stability. This research provides critical insights for the design of encapsulated food and pharmaceutical products, highlighting the imperative of strategic hydrocolloid selection to realize specific functional attributes and performance criteria.

Investigation of oil/water two-phase flow behavior in laminated shale porous media considering heterogeneous structure and fluid-solid interaction

The laminated structure of continental shale oil reservoirs introduces significant macro and micro heterogeneity, posing challenges for efficient shale oil extraction. Existing microscopic experimental and simulation methods are insufficient to accurately simulate the fluid flow behavior in mud–lime interactive laminated shale reservoirs. This study delves into the complexities of laminated shale reservoirs with a focus on their heterogeneous structure and wettability. Using scanning electron microscopy, we extracted the structural features of laminated shale reservoirs and established a Multicomponent and multiphase -multi relaxation time-Lattice Boltzmann model(MCMP-MRT-LBM) that considers nanoscale effects such as wall adsorption, liquid–solid slippage, and liquid–liquid slippage. We investigated the occurrence state, the flow behavior, and the phase seepage characteristics of crude oil in laminated shale at different water saturation stages and explored the reasons behind interlayer channeling and the conditions under which crude oil is mobile within limestone and mudstone layers. Then, we examined the impact of varying factors, including heterogeneous wettability, displacement pressure gradients, and pore size, on relative permeability, water injection capacity, sweep efficiency, and crude oil recovery in laminated reservoirs. The results indicate that wettability and pore size distribution, driven by capillary and viscous forces, dictate the occurrence state of remaining oil. Wettability primarily influences fluid distribution, whereas pore size distribution substantially impacts fluid morphology. It also highlights the pivotal role of flow velocity differences between layers in causing interlayer channeling. Increasing the capillary number promotes crude oil mobility within mudstone layers, with the initiation pressure gradient in mudstone layers being 2.5 times that of the limestone layer. The examination of the oil–water relative permeability reveals the dominance of pressure gradients in affecting oil flow capabilities, while pore size significantly influences water flow capacity. By optimizing various factors, it is possible to enhance water injection capacity and sweep efficiency, resulting in a substantial 5%–10% increase in crude oil recovery from laminated shale reservoirs.