Mobile Oil Research Articles

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.

Comprehensive evaluation of the organic-rich saline lacustrine shale in the Lucaogou Formation, Jimusar sag, Junggar Basin, NW China

To explore a comprehensive evaluation method for saline lacustrine shale, samples were collected from the shale strata of the Lucaogou Formation in the Jimusar Sag, Junggar Basin. Organic geochemical and mineralogical parameters were assessed through TOC evaluation, rock pyrolysis, and XRD. Quantitative analysis of pore structure was achieved using a combined low-pressure N2 adsorption and mercury intrusion. Optical microscopy and FE-SEM analyzed macerals and pore morphology, respectively, while 2D NMR identified varied hydrogen-containing components in the shale. The findings revealed predominance of inorganic pores in saline lacustrine shale strata, with a lower occurrence of organic pores. The saline lacustrine sediments were in the late stage of oil generation. The siltstone and type III3 carbonate felsic shale displayed an abundance of type II1 organic matter, low vitrinite and inertinite contents, high macroporous volumes and surface areas, and they possessed a high content and fluidity of free oil, despite being lower maturity (0.85%<Ro<1.1%), making them attractive for shale oil exploration. Finally, we propose a comprehensive evaluation method for saline lacustrine shale strata considering free oil content (26% contribution), pore structure (23% contribution), maturity (16% contribution), macerals (13% contribution), free oil mobility (12% contribution), and organic matter type (10% contribution), encompassing various lithofacies.

Research and Application of Carbon Capture, Utilization, and Storage–Enhanced Oil Recovery Reservoir Screening Criteria and Method for Continental Reservoirs in China

CCUS-EOR is a crucial technology for reducing carbon emissions and enhancing reservoir recovery. It enables the achievement of dual objectives: improving economic efficiency and protecting the environment. To explore a set of CCUS-EOR reservoir screening criteria suitable for continental reservoirs in China, this study investigated and compared the CCUS-EOR reservoir screening criteria outside and in China, sorted out the main reservoir parameters that affect CO2 flooding, and optimized the indices and scope of CCUS-EOR reservoir screening criteria in China. The weights of parameters with respect to their influences on CCUS-EOR were determined through principal component analysis. The results show that there are 14 key parameters affecting CO2 flooding, which can be categorized into four levels. For the first level, the crude oil-CO2 miscibility index holds the greatest weight of 0.479. It encompasses seven parameters: initial formation pressure, current formation pressure, temperature, depth, C2–C15 molar content, residual oil saturation, and minimum miscibility pressure. The second level consists of the crude oil mobility index, which has a weight of 0.249. This index includes four parameters: porosity, permeability, density, and viscosity. The third level pertains to the index of reservoir tectonic characteristics, with a weight of 0.141. It comprises two parameters: permeability variation coefficient and average effective thickness. Lastly, the fourth level focuses on the index of reservoir property change, with a weight of 0.131, which solely considers the pressure maintenance level. Based on the CCUS-EOR reservoir screening criteria and index weights established in this study, comprehensive scores for CCUS-EOR were calculated for six blocks in China. Among these, five blocks are deemed suitable for CCUS-EOR. Based on the comprehensive scoring results, a planning for field application of CCUS-EOR is proposed. The study provides a rational method to evaluate the CCUS-EOR reservoir screening and field application in continental reservoirs in China.

Oil migration from internal and external source rocks in an unconventional hybrid petroleum system, Montney Formation, western Canada

Unconventional hybrid petroleum systems are partially to entirely self-sourced. Their hydrocarbons are generated within internal (intraformational) organic-rich mudstone source rocks and subsequently migrate into adjacent organic-lean reservoir beds composed of sandstone, siltstone or carbonate. Hybrid systems with volumetrically dominant reservoir-quality rocks can additionally receive hydrocarbon charge by longer-range migration from external source rocks. However, few previous studies of hybrid systems have focused on the migration and mixing of hydrocarbons from both internal and external sources. To address this shortfall, this study presents an integrated organic geochemistry and stable carbon isotope investigation of drill-core and produced hydrocarbon liquid samples from two wells in a major unconventional hybrid petroleum system in the Montney Formation of western Canada. The results reveal distinct geochemical trends with increasing depth through the upper part of the Montney Formation including decreased C30+ biomarker compounds, increased depletion of saturate compared to aromatic δ13C values, and increased proportions of saturates and mobile oil. These trends indicate that oil from external source rocks of the overlying Doig Formation migrated into the upper part of the Montney Formation. Downward migration of externally sourced Doig oil resulted in a broad transition zone where Doig-sourced oil mixed with locally migrated lighter oil generated within internal Montney source rocks of slightly higher thermal maturity. This study sheds new light on the migration and mixing of disparate oil charges in the Montney Formation, and likely has widespread applicability to other similar unconventional hybrid petroleum systems that had hydrocarbon contributions from both internal and external source rocks.

Co-Injection of Foam and Particles: An Approach for Bottom Water Control in Fractured-Vuggy Reservoirs

Fractured-vuggy carbonate reservoirs are tectonically complex; their reservoirs are dominated by holes and fractures, which are extremely nonhomogeneous and are difficultly exploited. Conventional water injection can lead to water flooding, and the recovery effect is poor. This paper takes the injection of foam and solid particles to control bottom water as the research direction. Firstly, the rheological properties of foam were studied under different foam qualities and the presence of particles. The ability of foam to carry particles was tested. By designing a microcosmic model of a fractured-vuggy reservoir, we investigated the remaining oil types and the distribution caused by bottom water. Additionally, we analyzed the mechanisms of remaining oil mobilization and bottom water plugging during foam flooding and foam–particle co-injection. The experimental results showed that foam was a typical power-law fluid. Foam with a quality of 80% had good stability and apparent viscosity. During foam flooding, foam floated at the top of the dissolution cavities, effectively driving attic oil. Additionally, the gas cap is released when the foam collapses, which can provide pressure energy to supplement the energy of the reservoir. Collaborative injection of foam and solid particles into the reservoir possessed several advantages. On one hand, it inherited the benefits of foam flooding. On the other hand, the foam transported particles deep into the reservoir. Under the influence of gravity, particles settled and accumulated in the fractures or cavities, forming bridge plugs at the connection points, effectively controlling bottom water channeling. The co-injection of foam and solid particles holds significant potential for applications.

Experimental investigating of the effect of CO2 injection parameters on asphaltene precipitation and formation damage in live oil

AbstractWith the increasing consumption of oil in the world and increasing production of oil from oil reservoirs, the reservoir pressure starts to decrease. On the other side, the use of oil leads to an increase in carbon dioxide production in the environment and causes global warming.One of the effective methods of reducing the amount of carbon dioxide emitted into the atmosphere and increasing the reservoir's pressure is CO2‐EOR and carbon capturing and storing (CCS) which injects produced carbon dioxide from industrial sources into underground reservoirs. Carbon dioxide reduces oil viscosity and increases oil mobility producing an economical state. Moreover, with CO2‐EOR and CCS carbon dioxide can be stored in a depleted reservoir and helps reduce pollution and global warming.Besides the environmental and economic benefits due to reducing carbon dioxide emissions to the atmosphere and increasing oil production, CO2 injection causes various problems in the formation. Many experiments indicate that asphaltene precipitation and wettability alteration caused by asphaltene, dissolution/precipitation of rock, salt precipitation, and sludge formation are some of the problems that occur during CO2 injection operations in low pressure and temperature. However, few experiments evaluate asphaltene precipitation effective factors, such as pressure, injection rates, temperature, etc., in high temperatures and pressure (HPHT) near reservoir conditions. Therefore, there was a need for a comprehensive investigation of various factors and the impact of each of them on the asphaltene precipitation and formation damage in HPHT conditions, so this research was designed to help future simulation and industrial utilization.A core‐flood setup was prepared to conduct CO2 flooding experiments and formation damage studies in HPHT conditions. The main objective of this study was to evaluate the effect of different parameters including pressure, injection rate, and type of injected gas on asphaltene and its effect on formation damage caused by CO2 injection. The second goal of this study was to investigate the optimum injection in every section. The third goal was to determine the oil recovery during the process of CO2 injection in different conditions.The results showed that an injection rate of 0.1 cc/min and higher injection pressures minimized asphaltene precipitation and maximized oil recovery. Replacing CO2 with natural gas liquids (NGL) gas reduced oil production and asphaltene precipitation. Overall, the experiments demonstrated the importance of optimizing injection parameters to limit formation damage during CO2 flooding. © 2024 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley &amp; Sons Ltd.

Oil Shale In Situ Production Using a Novel Flow-Heat Coupling Approach.

Oil shale development, a significant global energy concern, involves the pyrolysis of kerogen, a process that can heat and contaminate groundwater with pyrolysis products. To address these challenges, this study introduces the ambient-temperature gas in situ heating (ATGIH) method as an alternative to traditional techniques. The ATGIH method establishes a low-temperature gas barrier to prevent water infiltration into the production zone by placing heating holes between the injection and production wells. The effectiveness of the ATGIH method in mitigating groundwater contamination during oil shale development is demonstrated through thermochemically coupled reservoir simulations. The study further discusses how gas injection enhances the flowability of mobile oil and gas phases into production wells and how controlling the Dykstra-Parsons coefficient, a measure of heterogeneity, can mitigate gravity segregation and aggregate viscous fingering issues. Our results show that well spacing is a critical factor in designing oil shale development, with a larger spacing resulting in higher energy efficiency but lower oil recovery rates. Furthermore, the study reveals that porosity decreases while permeability increases during pyrolysis due to thermal cracking and pore structure changes. It also highlights that heterogeneity-induced issues can be alleviated by increasing the correlation length to make the system more homogeneous. Therefore, the ATGIH method represents a key innovation in oil shale development, offering a solution that mitigates groundwater contamination while improving the energy efficiency.

Nano-structure of hydrolyzed polyacrylamide strengthened ultra stable nitrogen foam: Lab experiments and molecular dynamics simulation

Foam flooding is an extremely effective method of enhanced oil recovery used to address uneven utilization in strongly heterogeneous reservoirs. However, conventional foam is not stable and is unevenly distributed in oil reservoirs during conventional foam flooding. Hydrolyzed polyacrylamide-strengthened nitrogen foam (HSNF) was therefore proposed to overcome the defects of conventional foam flooding. In this investigation, a comprehensive method was utilized to understand the mechanisms of HSNF with regard to its stability and distribution in reservoirs. In situ experimental characterization and molecular dynamics simulations were designed to examine the characteristics of HSNF. Foam stability was analyzed as a function of the viscosity of the liquid phase, adsorption, and pressure for HSNF and conventional foam. Parallel core flooding experiments were conducted to compare the oil recovery efficiencies of HSNF and conventional foam. Molecular dynamics simulations were utilized to examine the nanostructure of HSNF in brine. Foam stability tests demonstrated that foam stability was enhanced by increasing the viscosity and pressure of the liquid phase and reducing the adsorption capacity of the surfactant. HSNF increased the foam half-life by a factor of 1.67–27.1. The parallel core flooding experiments showed that HSNF effectively initiated flow in low-permeability cores to increase the mobilization of oil even when the permeability ratio was 14.86. However, conventional foam only achieved similar performance at a permeability ratio of less than 10.64. The molecular dynamics simulations revealed that the addition of hydrolyzed polyacrylamide improved the uniform distribution of the oil displacement agent in porous media, inhibited the diffusion of nitrogen in the foam system, and enhanced the interactions between the water phase and crude oil. This suggests that HSNF is a promising oil recovery agent for use in low-porosity, low-permeability, and strongly heterogeneous sandstone reservoirs.

Comparative Assessment of Conventionally and Locally Sourced Surfactants for Enhancing Steam Flooding Techniques for Heavy Oil Recovery in Niger Delta

The recovery of heavy oil reserves presents a significant challenge in the petroleum industry due to its high viscosity and poor mobility characteristics. Steam flooding, as a thermal Enhanced Oil Recovery (EOR) technique, has shown promise in mobilizing heavy oil deposits. However, the limited success of conventional steam flooding in heavy oil reservoirs necessitates innovative approaches. This study explores the utilization of conventional and locally sourced surfactants in surfactant-enhanced steam flooding (SESF) for heavy oil recovery in the Niger Delta region. The study examines the selection, formulation, and injection of surfactants specifically tailored for heavy oil reservoir conditions. Laboratory experiments, core flooding tests, and numerical simulations are conducted to evaluate the impact of surfactants on interfacial tension reduction, wettability alteration, and improved oil mobility in heavy oil reservoirs subjected to steam flooding. The project’s findings demonstrate the significant potential of (SESF) for heavy oil recovery. The synergistic effects of surfactants and steam, including the reduction of oil-water interfacial tension, lead to increased oil production rates, reduced steam consumption, and enhanced sweep efficiency. Furthermore, economic assessments are conducted to evaluate the feasibility of implementing this approach on a field scale, considering both technical and economic aspects. This study not only contributes valuable insights to the field of heavy oil recovery but also underscores the practicality of surfactant-enhanced steam flooding as an environmentally responsible solution for unlocking the vast heavy oil reserves worldwide. The research bridges the gap between laboratory findings and real-world applications, offering a promising path forward for the sustainable development of heavy oil resources.

In-situ emulsification in low-tension surfactant/polymer systems: Impacts on enhanced oil recovery

The flow of two immiscible liquids in porous media can lead to fluid mixing, resulting in emulsions—where one phase is dispersed as droplets in the other. In reservoir rocks, natural surfactants and polar molecules, like asphaltenes, can promote oil–water emulsion formation. During chemically enhanced oil recovery processes (CEOR) such as surfactant, alkali, or surfactant-alkali flooding, in-situ emulsification is often seen as key to enhancing frontal stability and facilitating the piston-like displacement of oil by water. However, this work reports a minimal effect of in-situ emulsification on oil production during surfactant-polymer (SP) flooding. Experimental studies show this by injecting prepared emulsions into a multi pressure-tap core holder and examining emulsion formation in one reservoir core before moving it into a second core for oil displacement. This helps us understand the specific role of emulsions in oil mobilization. Factors like surfactant concentration, interfacial tension, and the timing of introducing the surfactant-polymer solution do influence the intensity of in-situ emulsification. Yet, the incremental oil recoveries show no significant differences. Through similar experiments, it is observed that ultra-low interfacial tension (IFT) in our surfactant-polymer system is the primary mechanism for oil mobilization. The slight increase in pressures suggests that in-situ emulsification has a limited role in increasing flow resistance during the ultra-low IFT SP flood process, potentially not improving the swept volume. This research can guide the development of systematic approaches to analyze the effects of in-situ emulsification on oil mobilization and evaluate chemical flooding processes.

Visualization of CO2-oil vanishing interface to determine minimum miscibility pressure using microfluidics

The determination of the minimum miscibility pressure (MMP) assumes paramount significance in evaluating CO2 enhanced-oil recovery strategies. We created a microfluidic method for determining the MMP of CO2 and oil samples by integrating the direct observation of the vanishing interface and the analysis of fluorescence intensity exhibited by oil samples. A microfluidic chip is designed with closed-end microchannels to mimic the blind-end fractures which contributes to reveal the complete picture of residual oil mobilization during CO2 miscible flooding. The maximum deviation of 3.83 % and 5.47 % unequivocally attested to the accuracy of our method by comparing measured MMPs with those reported in the literature and theoretically calculated in this study. The effects of alkane types, temperature and oil compositions on MMP was investigated. The MMPs for binary synthetic oils (C8 + C14) increased non-linearly with contents of tetradecane and increased significantly at C14 > 75 vol%. MMPs of nine n-alkanes, seven binary synthetic oils, four ternary synthetic oils and kerosene were provided reliably as the unprecedented new data. Such unique advantages as in-situ visualization, chip pattern customizability, user-independence, and the clear criterion render this research highly valuable for determining the MMP as well as elucidating the microscopic mechanisms underlying residual oil mobilization.

Experimental investigation of CO2 foam flooding-enhanced oil recovery in fractured low-permeability reservoirs: Core-scale to pore-scale

Fractured low-permeability reservoirs are characterized by poor reservoir physical properties, strong interlayer heterogeneity and the existence of natural and artificial fractures, resulting in significant water or gas channeling during flooding development. CO2 foam can effectively control the mobility of CO2 and ensure a more stable flooding front. In this study, taking into account the imbibition effect of the flooding process, the flooding performance under different injection methods and the influencing factors of foam pre-injection volume, back pressure and fracture complexity on CO2 foam flooding were systematically analyzed using fractured low-permeability core flooding experiments. In addition, the mechanism of CO2 foam flooding enhanced oil recovery (EOR) in low-permeability fractured reservoirs was obtained in combination with microscopic flooding experiments. The results show that the maximum recovery of 59.36 % can be obtained by soaking the core samples for 12 h with pre-injection of 0.4 PV CO2 foam followed by CO2 foam flooding, which adequately considers the imbibition effect during the flooding process. The pressure difference and oil recovery increases with increasing foam pre-injection amount, and the oil recovery with back pressure (2 MPa and 4 MPa) is significantly higher than that without back pressure; however, a further increase in back pressure has less impact on the recovery. The oil recovery rate of the fracture-free core is lower than that of the multiple fracture core during CO2 foam flooding but higher than that of the single fracture core, and the fracture complexity of the fractured cores has less impact on the final oil recovery. Microscopic experiments show that CO2 foam can effectively prevent channeling and improve the sweep efficiency. Soaking during the CO2 foam flooding process makes foam enter the matrix through the fracture, and CO2 dissolves after the foam breaks to increase the mobility of the crude oil, while the surfactant solution emulsifies the crude oil and changes the rock wettability. The unbroken foam can increase the sweep range, and the crude oil that flows into the fracture is carried by the subsequent injected foam to be recovered as foamy oil.

Using microbiological technology to increase oil recovery for terrigenous oil deposits

In this paper, the authors consider one of the widely used methods to increase the efficiency of flooding within the terrigenous reservoirs of the Volga-Ural oil and gas province - microbiological effects on the matrix of rocks to align the profile of pick-up and production. The process of the influence of metabolic products produced by microorganisms on the change in oil recovery coefficients over time has been comprehensively studied, as a result of which a significant increase in oil mobility has been established. The results of the measures and their main technical and economic indicators before the impact and after the operation are presented, on the basis of which it is recommended to use this technology to increase the efficiency of oil displacement in fields at the final stage of development as one of the alternative options for implementing high-quality energy resource management.

ОЦЕНКА КРИТЕРИЕВ ПРИМЕНЕНИЯ ПОЛИМЕРНОГО ЗАВОДНЕНИЯ В ОСЛОЖНЕННЫХ ПЛАСТАХ. ОБЗОР

Selection of the enhanced oil recovery method is based on applicability criteria, which are referred to in foreign literature as screening. To select the technology, the geological and physical parameters of the field are compared with the existing limits of applicability of the technology. Polymer flooding is a physical and chemical method of enhanced oil recovery, which has been used on an industrial scale for more than 60 years. The paper compares the applicability criteria of classical polymer flooding, adopted in the literature from 1985 to 1997, with modern projects carried out in the world. The main criteria, in terms of stability of polymer solution in reservoir conditions, key criteria determining the possibility of injecting the solution and additional criteria are highlighted. The main emphasis is made on the expediency of polymer flooding in high-temperature reservoirs containing low-viscosity oil or water of high mineralisation. Realised projects of enhanced oil recovery using polymers over the last 10 years are presented. Due to the appearance of modified representatives of high molecular weight compounds a large number of polymer flooding projects have been carried out in a wide range of conditions, which are presented in this paper: at reservoir temperature up to 140˚C, oil viscosity from 0.07 to 10000 mPa*s, as well as with highly mineralised formation water up to 250 g/l. Considering the implemented projects, it was revealed that the impact on increasing waterflood coverage is achieved not only by equalising the mobility of oil and displacing agent, but also by redistributing filtration flows of injected fluid from highly permeable and, consequently, already flushed zones to less permeable zones containing a large amount of residual reserves.

A FRACTAL-BASED OIL TRANSPORT MODEL WITH UNCERTAINTY REDUCTION FOR A MULTI-SCALE SHALE PORE SYSTEM

The challenges of modeling shale oil transport are numerous and include strong solid-fluid interactions, fluid rheology, the multi-scale nature of the pore structure problem, and the different pore types involved. Until now, theoretical studies have not fully considered shale oil transport mechanisms and multi-scale pore structure properties. In this study, we propose a fractal-based oil transport model with uncertainty reduction for a multi-scale shale pore system. The fractal properties of the shale pore system are obtained using high-resolution scanning electron microscope (SEM) imaging combined with laboratory core sample gas permeability measurements to reduce the model uncertainty. This fractal-based oil transport model accounts for boundary slippage, fluid rheology, the adsorption layer, and different pore types. We further pinpoint the effects of the fractal properties (pore fractal dimension, tortuosity fractal dimension), the shale pore properties (pore type, pore size, total organic carbon in volume), and the fluid properties (yield stress, liquid slippage, adsorption layer) on the shale oil permeability and mobile oil saturation using the proposed model. The results reveal that the size of the inorganic pores has the largest influence on the shale oil transport properties, followed by the yield stress, tortuosity fractal dimension, and the fractal dimension of the inorganic pores.

The mobilization mechanism of low oil saturation reservoirs

After fracturing with a guar fluid system in Chang 8 oil reservoir, some wells have high oil production, and some have low production and even only produce water. Therefore, a comparative study is carried out in oil-producing and water-producing wells. The results show that: ① Organic wax adsorbed in oil-producing and water-producing well core pores accounts for 95.39% and 56.67%, respectively, making wells strong oil-wet. A certain proportion of inorganic salts and some other oil-wet organic compounds exist in water-producing wells. ② Under the reservoir conditions, the oil wettability of the water-producing well core is strong, and its original formation wettability is also oil-wet. The original wettability of the oil-producing well formation is water-wet, with oil production capacity. ③ The core residual oil saturation using the guar fluid is 24.7%–29.87%. This results in no oil phase permeability or difficulty to mobilize oil in most oil reservoirs. ④ Forced displacement can mobilize oil in large pores and has a significant effect in producing well, with mobilization efficiency of 53.49%. This article elucidates the wettability formation and crude oil mobilization mechanism of two types of wells, providing direction for the development of this type of reservoir.