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The paper presents the results of experimental evaluation of oil displacement efficiency by flue gas of a thermal power plant, compared to water, for a carbonate reservoir in the Ural-Volga region. The experiments were performed under two different injection schemes using an original laboratory complex for coreflood studies, with recombined reservoir oil, model of formation water, reservoir core material, and under reservoir thermobaric conditions. It has been confirmed that due to the prevailing nitrogen content and low values of reservoir pressure and temperature, flue gas is ineffective as an independent displacement agent either for injection from the beginning of reservoir development or as a tertiary method after waterflooding. Taking into account the relevance of synergy between increasing oil recovery and sequestration of industrial emissions, evaluation of flue gas injection as part of water-gas mixtures (SWAG) is recommended.

Decreasing negative impact of industrial emissions to the atmosphere and prolonging fossil fuel usage period are urgent issues of fuel and energy sector. In view of this problem, injection of flue gases into oil fields to increase oil recovery may be considered as environmentally safe and economically rational way for beneficial use of greenhouse gas emissions. To effectively displace oil with flue gases it is important to consider many factors: influence of composition of the flue gases and oil, miscibility conditions, injection regimes, etc. Flue gases, a product of fuel combustion in air, can be produced as a result of oil self-ignition when air is injected into a reservoir with light oil (thermal gas method). Flue gases from natural gas, fuel oil or coal combustion in power plants or other processes that burn fossil fuels can also be used for injection into the reservoir. This paper presents an analysis of the world laboratory and industrial experience in studying efficiency of oil displacement using flue gases. Conclusions are presented about optimal criteria for implementation of this process and directions for further research.

The intricate geological characteristics of tight oil reservoirs, characterized by extremely low porosity and permeability as well as pronounced heterogeneity, have led to a decline in reservoir pressure, substantial gas expulsion, an accelerated decrease in oil production rates, and the inadequacy of traditional water injection methods for enhancing oil recovery. As a result, operators encounter heightened operational costs and prolonged timelines necessary to achieve optimal production levels. This situation underscores the increasing demand for advanced techniques specifically designed for tight oil reservoirs. An internal evaluation is presented, focusing on the application of molecular deposition film techniques for enhanced oil recovery from tight oil reservoirs, with the aim of elucidating the underlying mechanisms of this approach. The research addresses fluid flow resistance by employing aqueous solutions as transmission media and leverages electrostatic interactions to generate nanometer-thin films that enhance the surface properties of the reservoir while modifying the interaction dynamics between oil and rock. This facilitates the more efficient displacement of injected fluids to replace oil during pore flushing processes, thereby achieving enhanced oil recovery objectives. The experimental results indicate that an improvement in oil displacement efficiency is attained by increasing the concentration of the molecular deposition film agent, with 400 mg/L identified as the optimal concentration from an economic perspective. It is advisable to commence with a concentration of 500 mg/L before transitioning to 400 mg/L, considering the adsorption effects near the well zone and dilution phenomena within the reservoir. Molecular deposition films can effectively reduce injection pressure, enhance injection capacity, and lower initiation pressure. These improvements significantly optimize flow conditions within the reservoir and increase core permeability, resulting in a 7.82% enhancement in oil recovery. This molecular deposition film oil recovery technology presents a promising innovative approach for enhanced oil recovery, serving as a viable alternative to conventional water flooding methods.

Carbon dioxide capture, EOR-utilization and storage (CCUS-EOR) are the most practical and feasible large-scale carbon reduction technologies, and also the key technologies to greatly improve the recovery of low-permeability oil fields. This paper sorts out the main course of CCUS-EOR technological development abroad and its industrialization progress. The progress of CCUS-EOR technological research and field tests in China are summarized, the development status, problems and challenges of the entire industry chain of CO2 capture, transportation, oil displacement, and storage are analyzed. The results show a huge potential of the large-scale application of CCUS-EOR in China in terms of carbon emission reduction and oil production increase. At present, CCUS-EOR in China is in a critical stage of development, from field pilot tests to industrialization. Aiming at the feature of continental sedimentary oil and gas reservoirs in China, and giving full play to the advantages of the abundant reserves for CO2 flooding, huge underground storage space, surface infrastructure, and wide distribution of wellbore injection channels, by cooperating with carbon emission enterprises, critical technological research and demonstration project construction should be accelerated, including the capture of low-concentration CO2 at low-cost and on large-scale, supercritical CO2 long-distance transportation, greatly enhancing oil recovery and storage rate, and CO2 large-scale and safe storage. CCUS-EOR theoretical and technical standard system should be constructed for the whole industrial chain to support and promote the industrial scale application, leading the rapid and profitable development of CCUS-EOR emerging industrial chain with innovation.

The occurrence state of oil, gas, and water plays a crucial role in exploring shale reservoirs. In this study, molecular dynamics simulations were used to investigate the occurrence states of these fluids in shale nanopores. The results showed that when the alkane is light oil, in narrow pores with a width less than 3 nm, oil molecules exist only in an adsorbed state, whereas both adsorbed and free states exist in larger pores. Due to the stronger interaction of water with the rock surface, the adsorption of oil molecules near the rock is severely prohibited. Oil/water/gas occurrence characteristics in the water-containing pore study indicate that CO2 gas can drive free oil molecules out of the pore, break water bridges, and change the occurrence state of water. During displacement, the gas type affects the oil/gas occurrence state. CO2 has strong adsorption capacity, forming a 1.45 g/cm3 adsorption layer on the rock surface, higher than oil’s density peak of 1.29 g/cm3. Octane solubility in injected gases is CO2 (88.1%) > CH4 (76.8%) > N2 (75.4%), with N2 and CH4 having weak competitive adsorption on the rock. The investigation of different shale reservoir conditions suggests that at high temperature or low pressure, oil/gas molecules are more easily displaced, while at low temperature or high pressure, they are tightly adsorbed to the reservoir rock. These findings contribute to the understanding of fundamental mechanisms governing fluid behavior in shale reservoirs, which could help to develop proper hydrocarbon recovery methods from different oil reservoirs.

The carbon capture, utilization and storage (CCUS) technique is widely applied in order to solve energy shortages and global warming, in which CO2 storage plays an important part. Herein, the CO2 storage in reservoir pores with a dead-end is investigated using a molecular dynamics simulation. The results indicate that, when a CO2 molecule flows through a reservoir pore towards its dead-end, it is readily captured inside said dead-end. When the pressure difference of the CO2 injection increases, the transport speed of the CO2 becomes faster, and the storage efficiency increases. The rate constants for the absorption of the carbon dioxide at 5 MPa, 10 MPa, and 15 MPa are 0.47 m/s, 2.1 m/s, and 3.1 m/s. With the same main channel, a narrower dead-end with less oil molecules would cause a smaller spatial potential resistance, which would lead to a faster CO2 replacement and storage process. The 3 nm main channel with a 1.5 nm dead-end model had the highest absorption rate of 5.3 m/s out of the three sets of models with different dead-ends. When the dead-end’s width was constant, the rate constants for the absorption of carbon dioxide in the 6 nm main channel with a 1.5 nm dead-end model was 1.8 m/s, which was higher than that of the 3 nm–1.5 nm model. This study investigates the mechanism of CO2 storage in reservoir pores with a dead-end at the molecular level and provides a scientific basis for the practical application of CO2 storage.

This study explored potential applications of a mixtures of nanoparticles and wormlike micelles as a chemica flooding agent in a specific Bohai Bay Oilfield. Sample preparations were carried out, based on two different zwitterionic surfactants cetylamidopropyl hydroxypropyl sulfobetaine and tetradecyl propyl sulfobetaine. A wormlike micelle which can significantly improve the viscosity in simulatated injected water was prepared, and a nanoparticle wormlike micelle was formed by directly introducing nano silica solid. The results of transmission electron microscope showed that the formation of long cetylamidopropyl hydroxypropyl sulfobetaine/tetradecyl propyl sulfobetaine composite wormlike micelles endowed the water phase with high viscosity. By adjusting the amount of surfactant in the range of 0.2 ∼ 0.5 wt%, the water phase viscosity can be controlled between 10 50 mPa·s. This work provided insights either in developing a new high-efficiency oil displacement agent, or offering a new idea for the rheological study on wormlike micelle agents.

Abstract The gas and chemical flooding for reservoir stimulation with residual hydrocarbons reserves are highly relevant problem of current oil and gas recovery strategy. The objective of this paper is laboratory study and field implementation of new gas-EOR technology—in situ carbon dioxide generation technique for CO2-liquid slug formation under oil displacement, increasing the reservoir sweep efficiency and residual oil recovery. This paper presents a summary of a wide range of laboratory tests conducted on different core samples and chemical compositions. Several physical and hydrodynamic phenomena of in situ CO2 generation in highly permeable zones of a porous medium have been investigated as a part of complex study, which involved laboratory tests on the field-scale industrial technology applications, determination of optimal concentrations of foaming agents and inhibiting additives in gas-releasing solutions, etc. The results of laboratory experiments showed that the incremental recovery ranged between 30 and 35% oil original in place. The unique results of the field implementation provide developing an optimal technological scheme of reservoir stimulation with residual oil reserves both onshore and offshore oil fields. Technology of in situ CO2 generation was applied on the group of wells on Penglai offshore oil field (Bohai Bay). Incremental oil production for field operation was 37,740 bbl of crude oil. Theoretical and laboratory studies, as well as the outcomes of industrial implementation of a new method of residual oil recovery, using a CO2-slug confirm technology and economic profitability of the proposed solution.

The relevance of the research. Currently, most of oil fields of Russia have entered the late stage of development. As there is the depletion of easily recoverable oil reserves, more and more efforts are directed at creating technologies and development methods that allow producing hydrocarbons in difficult conditions. For further development of fields with hard-to-recover reserves, the introduction of new methods for increasing oil recovery and the use of new reagents are required. A significant role in this matter is given to chemical methods, in particular the use of solutions of surfactants. Exposure of aqueous surfactant solutions improves the rheological and filtration characteristics of oil by reducing interfacial tension and increasing wetting ability. in this relation, the task of choosing a surfactant for use in the waterflooding system of reservoirs, as well as the development of methodological approaches for their selection, is of current interest. The main aim of the research is toform a methodological approach to study the surfactants used in the waterflooding system to increase oil recovery. Object: carbonate collectors of Udmurt Republic. Methods: laboratory studies of compositions, device for determining the surface tension of surfactant solutions – stalagmometer «Rubin-02 A», filtration units with simulation of formation conditions of UIP-5VG and AFS-300, centrifuge process. Results. The paper identifies the urgent problem – the process of selecting surfactant technology for effective application in the waterflooding system for achieving the highest oil recovery. The surface-active substances that have found active industrial use in the fields of Russia and beyond are analyzed. The physicochemical and technological properties of Russian-made surfactants were evaluated in accordance with the passport characteristics, the requirements of the Provisions of a subsurface user enterprise, and the suitability of chemicals for further use was determined. The paper considers the methodology and results of determining the coefficient of oil displacement with aqueous surfactant solution on core samples taken from deposits in the Udmurt Republic. An express method for assessing the oil-displacing ability of a surfactant is proposed. It is more economical and energy-efficient in comparison with standard filtration studies. According to the results of filtration tests on the core, it was found that the proposed method is comparable with the studies. In general, the proposed methodology for the choice of surfactant composition is possible for implementation in local regulatory documents of a subsoil user enterprise and for use in order to select the necessary reagent to increase oil recovery.

Four products were obtained from sodium dodecylbenzene sulfonate (SDBS) and formaldehyde (40% solution) using a simple reaction. The products were characterized by TGA, IR, UV and MS to confirm the major chemicals in each sample. The new products could reduce the interfacial tension between oil and water in the experimental temperature range further compared to SDBS. The emulsion ability was also enhanced by SDBS-1 to SDBS-4. The oil-displacement efficiencies of SDBS-1 to SDBS-4 were obviously higher than that of SDBS, and the oil-displacement efficiency of SDBS-2 was the best, with an efficiency of 25%. The experimental results all indicate that these products have an excellent ability to reduce oil–water interfacial tension and that they can be used in the oil and petrochemical industry for oil production and have certain practical uses.

Multiphase flows in porous media are widespread in nature and various technologies. One of the most common examples of this kind of task is the task of recovering oil from the rock. This article describes a mathematical model of the flow of a two-phase (immiscible) liquid based on a new approach of network hydrodynamics for a highly branched microchannel medium (simulating a porous space in the rock). The coupling of the flow and pressure fields in the network is performed using a well-proven SIMPLE algorithm in CFD problems; this approach allows us to use effective approaches to modeling 3D tasks. Phase transfer over the network is carried out by an explicit method with an adaptive time step. The article presents the results of verification of the model, with analytical calculations and in comparison with the results of experimental studies. As an experiment, the displacement of oil from a microchip (Dolomite: 3200284) simulating a porous medium was simulated. The good qualitative and quantitative compliance with the results calculated and the results of the experiment show the correct functioning of the model.

In this paper, a betaine-based gel containing 2.0% erucamide propyl betaine (EAPB), 0.5% oleic acid amide propyl betaine (OAPB), and 0.1% KCl was prepared for use as a fracturing fluid. The performance evaluation showed that KCl may improve the temperature resistance and increase the viscosity of the optimized fracturing fluid. At 80 °C, the apparent viscosity of the viscoelastic surfactant (VES)-based fracturing fluid was approximately 50 mPa·s. Furthermore, the gel had high shear resistance, good viscosity stability, and high sand-carrying performance. After being sheared at 170 s−1 for 60 min, the reduction in viscosity was 13.6%. The viscosity of the gel was relatively stable at room temperature (27 °C) for one week. In a suspension containing 10% sand (particle size < 0.45 mm, density = 2.75 g cm−3), the settling velocity of proppant particles was 1.15 cm h−1. In addition, we detected that the critical micelle concentration of this gel was approximately 0.042 wt%. The viscosity could be reduced to

The reservoir heterogeneity of Q oilfield is more severe after long-term water injection development, and water flooding is ineffective. In this study, the combined technologies of profile control, profile control and flooding, and oil displacement were proposed to improve the water flooding development effect. Then, the influence of the well pattern type on the remaining oil distribution, after development, was investigated. Cr3+ polymer gel, which has an optimal gel-forming effect, was used as the profile control agent. Moreover, the entire molecular structure had a “network” structure. A polymer microsphere was used as a profile control and flooding agent, which showed a good hydration expansion capacity. The initial particle size distribution had a range of 7.2–11.1 μm, and the expansion multiple was 4.35–5.64 after 7 days. The surfactant was an oil displacement agent, and the interfacial tension was approximately 5.08–5.11 × 10−1 mN/m. After the “profile control + profile control and flooding + oil displacement” technologies, the horizontal well pattern had a large seepage area. The effect of expanding the sweep volume was significant, and the remaining oil saturation in each stage was lower than those of the vertical and horizontal–vertical combined well patterns. Compared with the first water flooding stage, the remaining oil saturation values of the three permeable layers changed by 11.9%, 17.3%, and 19.8% during the subsequent water flooding stage.

After the heterogeneous reservoir enters the middle and late stages of development, the problems due to water injection will become increasingly prominent. However, the requirements for water injection in reservoir development are also increasing. So how do we solve this big problem? And how to scientifically manage water injection wells, promote oil with water, improve water displacement efficiency, and make the reservoir enter a benign development state? First of all, we need to firmly remember the idea of “water well first, pay equal attention to oil and water”, lock the key points of water injection, and comprehensively improve the water injection management level from the aspects of surface, wellbore and underground, so as to consolidate the foundation of stable oil reservoir production.

Viscosity losses and high degradation factors have a drastic impact over hydrolyzed polyacrylamides (HPAM) currently injected, impacting the oil recovery negatively. Previous studies have demonstrated that biopolymers are promising candidates in EOR applications due to high thermochemical stability in harsh environments. However, the dynamic behavior of a biopolymer as scleroglucan through sandstone under specific conditions for a heavy oil field with low salinity and high temperature has not yet been reported. This work presents the rock–fluid evaluation of the scleroglucan (SG at 935 mgL−1) and sulfonated polyacrylamide (ATBS at 2500 mgL−1) to enhance oil recovery in high-temperature for heavy oils (212 °F and total dissolved solid of 3800 mgL−1) in synthetic (0.5 Darcy) and representative rock samples (from 2 to 5 Darcy) for a study case of a Colombian heavy oilfield. Dynamic evaluation at reservoir conditions presents a scenario with stable injectivity after 53.6 PV with a minimal pressure differential (less than 20 psi), inaccessible porous volume (IPV) of 18%, dynamic adsorption of 49 µg/g, and resistance and residual resistance factors of 6.17 and 2.84, respectively. In addition, higher oil displacement efficiency (up to 10%) was obtained with lower concentration (2.7 times) compared to a sulfonated polyacrylamide polymer.

Polymer flooding is a promising chemical enhanced oil recovery (EOR) method, which realizes more efficient extraction in porous formations characterized with nanoscale porosity and complicated interfaces. Understanding the molecular mechanism of viscoelastic polymer EOR in nanopores is of great significance for the advancement of oil exploitation. Using molecular dynamics simulations, we investigated the detailed process of a viscoelastic polymer displacing oil at the atomic scale. We found that the interactions between polymer chains and oil provide an additional pulling effect on extracting the residual oil trapped in dead-end nanopores, which plays a key role in increasing the oil displacement efficiency. Our results also demonstrate that the oil displacement ability of polymer can be reinforced with the increasing chain length and viscoelasticity. In particular, a polymer with longer chain length exhibits stronger elastic property, which enhances the foregoing pulling effect. These findings can help to enrich our understanding on the molecular mechanism of polymer enhanced oil recovery and provide guidance for oil extraction engineering.