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Understanding the CO2 displacement mechanism in ultra-low-permeability reservoirs is essential for improving oil recovery. In this research, a series of displacement experiments were conducted on sandstone core samples from the Chang 6 reservoir in the Huaziping area using a multifunctional core displacement apparatus and Nuclear Magnetic Resonance (NMR) technology. The experiments were designed under conditions of constant pressure, variable pressure, and constant effective confining stress to simulate various reservoir scenarios. The results indicated that the distribution characteristics of the pore structure in the rock samples significantly influenced the CO2 displacement efficiency. Specifically, under identical conditions, rock cores with a higher macropore ratio exhibited a significantly enhanced recovery rate, reaching 68.21%, which represents a maximum increase of 31.97% compared to cores with a lower macropore ratio. Though fractures can facilitate CO2 flowing through pores, the confining pressure applied during displacement caused a partial closure of fractures, resulting in reduced rock permeability. Based on the oil-to-gas ratio and oil recovery in the outlet section of the fractured rock samples, the CO2 displacement process exhibited five stages of no gas, a small amount of gas, gas breakthrough, large gas channeling, and gas fluctuation. Although the displacement stage of different cores varies, the breakthrough stage consistently occurs within the range of 2 PV. These insights not only enhance our understanding of CO2 displacement mechanisms in low-permeability reservoirs but also provide actionable data to inform the development of more effective CO2-EOR strategies, significantly impacting industrial practices. [ABSTRACT FROM AUTHOR]

The most popular oil displacement technique in oilfield development is water flooding, yet sustained water flooding makes it simple to create water channeling in the formation, lowering development efficiency. A high strength agar was synthesized by using raw agar and 3-chloro-2-hydroxy-propyl trimethyl ammonium chloride, and it was then combined with PAM to prepare a plugging system to address the issue of water channeling in old oilfields. The successful synthesis of a modified agar was demonstrated by FITR, EM, TG/DSC, and its temperature resistance and agar strength were improved. Gelation and flow experiments were used to test the gelation and plugging characteristics of the plugging system. The results show that the plugging system is a pseudoplastic fluid, the temperature resistance less than 120 °C, the salinity resistance less than 1 × 105 mg/L, the gelation time of is 1 ∼ 3d, the gelation strength reaches grade I, the resistance coefficient less than 10, the breakthrough pressure gradient greater than 20 MPa·m−1, the plugging ratio greater than 90%, and the oil recovery ratio increases 22.8%. This work's study has a significant impact on enhancing oil recovery. [ABSTRACT FROM AUTHOR]

The relevance of the technical and economic evaluation of the application of enhanced oil recovery methods at oil fields at the final stage of development is related to the need to recover the remaining reserves, including hard-to-recover (HTR) reserves, the share of which is growing annually. Currently, there are many effective enhanced oil recovery (EOR) methods for different process conditions, but their application has different effects based on the combination of methods, techniques and production conditions. The aim of this study was to approach the scaling of the effect of the application of modern EOR using the methodology of the clustering of wells with similar technological characteristics. This paper proposes a methodology for the selection of candidate wells to form clusters based on a set of indicators that determine the choice of enhanced oil recovery technology in oil fields at the final stage. The technological efficiency of sidetracking and multistage hydraulic fracturing application was evaluated based on the analytical method of well flow rate estimation. By applying cluster analysis to selected wells, three clusters were formed, each including three wells, united by the geological properties of their reservoir rocks and the filtration–capacitive properties of the oil. After this, the optimal technologies were selected for two clusters—hydraulic fracturing and sidetracking. The accumulated oil production, recovered due to the application of the technologies, from six wells for the first 7 years after the operation was estimated at 306.92 thousand tons of oil. Due to the achieved technological effect, the economic efficiency of the development of the studied oil field will increase due to the proceeds from the sales of the extracted additional oil. The results of this study can be used in the calculation of technical and economic efficiency at oil fields with similar conditions. [ABSTRACT FROM AUTHOR]

A large volume of water is bypassing oil and comes up without being able to push it out from the reservoir after organic material adsorption. This work investigates hydrophobicity effect on rock wettability, oil recovery, and relative permeability. The μXRF was used to characterize sand cores, and a contact angle goniometer to determine fluids contact angle. Oil recovery was evaluated by measuring the incremental oil volume recovered in a glass and PVC capillary designed micromodel. Relative permeability was studied using the steady state method, and the wettability was determined by the Amott method. The results show that cores are mainly composed of quartz 86.04%. Oil recovery was 30.50% for oil-wet state; where the wettability index was −0.283. Thereafter, it has been demonstrated that the surfactant solution increases the oil recovery with 23.54 ℅. Adsorption of surfactants on functional groups of PVC change the contact angle between water and PVC's surface from 112° to 39°, decrease the IFT and restore the water-wet state. PVC debris presents efficient new method to determine the water by pass effect on oil recovery. The findings of this study help for better understanding the surfactant-oil displacements during water flooding in light oil reservoirs with impaired wettability. [ABSTRACT FROM AUTHOR]

Polymer gel was widely used as water shutoff agent in mature oil fields. And the results of single-phase plugging experiments show that the plugging rate of the polymer gel to the oil phase is lower than that of the water phase. However, the disproportionate permeability reduction (DPR) mechanism of polymer gels still remains controversial. In this paper, we used four gel formulations including polyethyleneimine (PEI) and phenol-formaldehyde crosslinked gel with and without adding laponite to investigate the effect of gel elastic property on the water shutoff mechanism. The result of sand pack flooding experiments shown that the gel with higher elastic modulus has better effects on decreasing water cut and increasing oil recovery. After adding laponite, the elastic modulus of phenol-formaldehyde crosslinked gel increased from 64.2 Pa to 192 Pa, and the elastic modulus of PEI crosslinked gel increased from 27.4 Pa to 36.5 Pa. Compared to the phenol-formaldehyde-HAPM gel, the oil recovery of laponite-phenol-formaldehydeHPAM gel increased by 5.2% and the maximum water cut decreased by 8.3%. Besides, comparing with PEI-HPAM gel, the oil recovery of laponite-PEI-HPAM gel increased by 2.7% and the water cut dropped by 27.8%. In the meanwhile, the laponite-phenol-formaldehyde-HPAM gel with higher elastic modulus obviously swells in the formation water but almost remains constant in oil at 105(C. The mass of gel soaked in the formation water increased from 42 g to 96 g and the gel volume increased by 300% within 48 hours. This study improves the understanding of the DPR mechanism of polymer gel for water shutoff. [ABSTRACT FROM AUTHOR]

Produced Water (PW) represents the largest waste stream in the oil and gas industry. As a water resource and as a source of valuable minerals such as alkali salts, it is has been highly under-valued, especially in hyper-arid regions. The beneficial use of PW ranges from water reinjection to elevated oil recovery from reservoirs with almost instantaneous returns, to the extraction of minerals from PW, which involves a number of different processes and setups. The economic value of PW-derived end products offers alternative revenue sources, with market fluctuations and conditions different from those of the hydrocarbon market. The end products of water and industrial salt support local industries such as agriculture, reflecting positively on the gross domestic product (GDP). Furthermore, resource extraction from PW of the oil and gas industry helps countries augment their circular economy. In this regard, the economic feasibility of three scenarios—the use of PW for oil recovery, the use of PW as an alternate source of water and industrial salt, and a hybrid process of both—is explored. The results show that there is great potential for water reuse in Enhanced Oil Recovery operations, as well as in the reduction in freshwater consumption for oil- and gas-extraction operations in the state of Kuwait by up to 4.8 percent when PW generated by SK oilfields is considered, and by 42 percent if PW from all oilfields in Kuwait is reused in the same manner. [ABSTRACT FROM AUTHOR]

Abstract Using surfactants to extract oil, the anionic surfactant Karamay petroleum sulfonate (KPS), the zwitterionic surfactant octadecyl betaine (BS-18) and the nonionic surfactant coconut oil fatty acid diethanolamide (6501) were selected for adsorption experiments with minerals contained in the conglomerate reservoir with different mineral compositions to study the adsorption law of different types of surfactants. Zeolite and montmorillonite, which have the highest specific surface area and zeta potential among the minerals in the conglomerate reservoir, have the most obvious adsorption effect on surfactants, resulting in a large amount of adsorption of KPS and BS-18. The three types of surfactants were then used to conduct physical simulation oil recovery experiments with conglomerate core samples, and the results showed that 6501 had better overall performance, the best adsorption resistance, and a higher degree of recovery in oil recovery experiments, which provided a basis for the selection of surfactants in the process of chemical drive in conglomerate reservoirs.

The objective of this study is to utilize cost-effective renewable substrates derived from agro-food wastes for the production of biosurfactant by Bacillus megaterium, which was isolated from petroleum sludge. Various agro-food waste materials, namely potato peelings (PP), rice cooking water (RW), biscuit by products (BB), carob pods (CP), and eggshells, were evaluated as nutrient sources for bacterial growth compared to a synthetic medium (SM). The results indicate that the medium comprising carob pods, potato peels supplemented with eggshells promoted the growth of the bacteria and the production of Biosurfactants at a rate of 150 mg/l and 140 mg/l respectively. The biosurfactant exhibited an emulsification index (E24) of 55.23 ± 0.32%, 46.47 ± 3% 43.80 ± 0.4%, 18.33 ± 0.25% and 20 ± 0.11% for PP, CP, SM, BB and RW respectively. The biosurfactant produced from PP had the ability to decrease the surface tension of water from 74 to 39.38 mN/m, with a critical micelle concentration (CMC) of 15 mg/L. The chemical characterization of purified biosurfactant was done using Fourier-transform infrared spectroscopy (FTIR) and Thermal gravity (TG), as well as differential scanning calorimetry (DSC) analysis (TG/DSC), revealing the functional groups and thermostability of the biosurfactant. The DSC spectrum for PP biosurfactant showed the highest thermostability with crystalline temperature (Tc) of 150 °C and melting point (Tm) of 295 °C. The extracted biosurfactant was mixed with petroleum sludge, composed of heavy oil, 40.64 ± 0.19% of extracted oil was obtained after 5 h of reaction while using PP based medium. [ABSTRACT FROM AUTHOR]

Counter-current imbibition can improve the recovery efficiency of complex fractured reservoirs, but there are few studies on the pore-scale mechanism and the factors affecting the recovery efficiency. This paper attempts to track the microscopic oil–water imbibition process through phase field method simulation, revealing the distribution characteristics of oil and water phases at different stages, as well as the sudden change characteristics of pressure and velocity at the instant of oil film rupture. Then, the influence of fracture aperture, capillary number and viscosity ratio on oil recovery efficiency is discussed. Results indicate that the microscopic imbibition process can be divided into 4 stages: the oil film forms after oil–water contact, then the oil film ruptures to form oil droplets, then the oil–water line moves outward from the large pore, and finally the oil droplets gather to discharge from the fracture. It is also found that there will be sudden changes at the moment of oil film rupture, the pressure drops sharply and the velocity increases sharply. Moreover, there exists a critical fracture aperture which is approximately 10 times the average pore size, and if the fracture is smaller than the critical fracture aperture, a dead oil zone occurs, which affects recovery. Additionally, LogM-LogCa stability diagram is constructed which is mainly dominated by viscous forces, capillary forces. As the capillary number increases, the recovery efficiency shows an overall decreasing trend. When the viscosity ratio was greater than 10, there was no significant change in the recovery efficiency, influenced by the weakening of the dominant role of viscous forces. New findings are beneficial to enhancing the recovery efficiency of low permeability reservoirs. [ABSTRACT FROM AUTHOR]

Abstract Asphaltene precipitation in oil reservoirs, well equipment, and pipelines reduces production, causing pore blockage, wettability changes, and decreased efficiency. Asphaltenes, with their unique chemical structure, self-assemble via acid–base interactions and hydrogen bonding. Nano-inhibitors prevent asphaltene aggregation at the nanoscale under reservoir conditions. This study investigates the effect of two surface-modified nanoparticles, silica, and calcium carbonate, as asphaltene inhibitors and oil production agents. The impacts of these nano-inhibitors on asphaltene content, onset point, wettability, surface tension, and oil recovery factor were determined to understand their mechanism on asphaltene precipitation and oil production. Results demonstrate that these nano-inhibitors can significantly postpone the onset point of asphaltene precipitation, with varying performance. Calcium carbonate nano-inhibitor exhibits better efficiency at low concentrations, suspending asphaltene molecules in crude oil. In contrast, silica nano-inhibitor performs better at high concentrations. Wettability alteration and IFT reduction tests reveal that each nano-inhibitor performs optimally at specific concentrations. Silica nano-inhibitors exhibit better colloidal stability and improve oil recovery more than calcium carbonate nano-inhibitors, with maximum oil recovery factors of 33% at 0.1 wt.% for silica and 25% at 0.01 wt.% for calcium carbonate nano-inhibitors.

The study of the law and degree of injection and extraction coupling in old oil areas is a difficult point that affects the recovery rate. The traditional experimental and numerical simulation research methods lack validation and working condition prediction. This study has improved the working steps and supplemented the lack of program validation link through the methods of data prediction and mathematical argumentation. This program has been implemented in the Tamkou field. In addition, we determined the relationship between different permeability, crude oil viscosity, and recovery rate influencing factors on recovery under the premise of a fixed well network, and the DGM (1,1) model prediction yielded the recovery rates of 8.93 and 12.08 for the next 2 time nodes. The analyses showed that adopting the means of water blending and dosing to adjust the crude oil viscosity to 90 mPa s, and adopting the water injection rate of 5 mL/min to extract the best recovery rate. Min water injection rate is optimal for extraction. [ABSTRACT FROM AUTHOR]

This work employs the phase field method combined with a realistic microscopic heterogeneous pore structure model to conduct numerical simulations of CO2–oil two-phase flow. This study investigates the diffusion behavior of CO2 during the displacement process and analyzes the impact of various parameters such as the flow rate, the contact angle, and interfacial tension on the displacement effect. The results indicate that, over time, saturated oil is gradually replaced by CO2, which primarily flows along channels with larger throat widths and lower resistance. The preferential flow paths of CO2 correspond to high flow rates and high pore pressures occupied by CO2. As the injection rate increases, the CO2 filtration rate increases, CO2 movement becomes more pronounced, and CO2 saturation rises. Beyond the optimal flow rate, however, the displacement effect worsens. The wettability of the porous medium predominantly determines the CO2 migration path during the displacement process. As the contact angle increases, CO2 wettability towards the rock improves, significantly enhancing the displacement effect. Under different interfacial tension conditions, the recovery rate increases with the amount of CO2 entering the porous medium, but no clear correlation is observed between interfacial tension and the recovery rate. Therefore, it is challenging to further improve the recovery rate by altering interfacial tension. The viscosity ratio affects wettability and thereby influences the displacement effect. Lower viscosity ratios result in reduced wettability effects, making CO2 diffusion more difficult. This study provides theoretical guidance and technical support for CO2-EOR (Enhanced Oil Recovery) in highly heterogeneous reservoirs on a field scale. [ABSTRACT FROM AUTHOR]

In order to solve the problems of conventional water injection development difficulties and low recovery factor in low-permeability reservoirs, the method of high-pressure air drive is adopted to achieve the purpose of reservoir energy enhancement and efficiency improvement. This paper conducted an experimental study on the mechanism of low-temperature oxidation (LTO) for crude oil in the process of high-pressure air flooding, elaborated the relationship between the LTO properties of crude oil and the temperature, pressure, and water saturation of the reservoir, and analyzed the differences in LTO oxygen consumption and oil components under different reaction conditions. In addition, combined with the air flooding physical simulation experiment, the dynamic evolution law of recovery rate in the air flooding process was revealed. Findings from this inquiry indicate that an escalation in the oxidation temperature significantly amplifies the oxygen incorporation reaction within the crude oil matrix. This augmentation in oxidative conditions leads to an uptick in oxygen consumption, which subsequently precipitates a reduction in the lighter fractions of the oxidized oil while enriching its heavier components. Elevated pressures were found to enhance the propensity for the amalgamation of unstable hydrocarbons with oxygen, fostering comprehensive and heterogeneous oxidation reactions. Notably, an excessive presence of water was observed to detrimentally affect the thermal efficacy of crude oil oxidation processes. In the context of low-permeability reservoirs, air injection techniques have emerged as superior in effectuating oil displacement, although an increase in injection pressures has been associated with the phenomenon of gas channeling. Interestingly, adopting a sequential strategy of initiating water flooding before air flooding facilitated the conveyance of high-pressure air via established flushing channels, although it appeared to attenuate the intensity of crude oil oxidation, culminating in an oil recovery efficiency peaking at 51%. [ABSTRACT FROM AUTHOR]

Asphaltene precipitation in oil reservoirs, well equipment, and pipelines reduces production, causing pore blockage, wettability changes, and decreased efficiency. Asphaltenes, with their unique chemical structure, self-assemble via acid–base interactions and hydrogen bonding. Nano-inhibitors prevent asphaltene aggregation at the nanoscale under reservoir conditions. This study investigates the effect of two surface-modified nanoparticles, silica, and calcium carbonate, as asphaltene inhibitors and oil production agents. The impacts of these nano-inhibitors on asphaltene content, onset point, wettability, surface tension, and oil recovery factor were determined to understand their mechanism on asphaltene precipitation and oil production. Results demonstrate that these nano-inhibitors can significantly postpone the onset point of asphaltene precipitation, with varying performance. Calcium carbonate nano-inhibitor exhibits better efficiency at low concentrations, suspending asphaltene molecules in crude oil. In contrast, silica nano-inhibitor performs better at high concentrations. Wettability alteration and IFT reduction tests reveal that each nano-inhibitor performs optimally at specific concentrations. Silica nano-inhibitors exhibit better colloidal stability and improve oil recovery more than calcium carbonate nano-inhibitors, with maximum oil recovery factors of 33% at 0.1 wt.% for silica and 25% at 0.01 wt.% for calcium carbonate nano-inhibitors. [ABSTRACT FROM AUTHOR]

Water trapping typically occurs during the drilling process when a sizable volume of drilling fluid is exposed to the area around the wellbore. This phenomenon, which is poorly studied and investigated by few studies, represents the gap in this work. The trapped water causes a reduction in the flow of oil. By lowering the interfacial tension, products such as alcohols and cationic surfactants have been used to reverse the rock's wettability through adsorption, thereby reducing the trapped water saturation. Samples based on reservoir rock cuttings with a determined porosity of 12.72°C and permeability of 12.54 md were used to simulate low-porosity and low-permeability sandstone reservoirs. In this work, an alcoholic-treated water mixture is injected into samples that were initially saturated with simulated oil under experimental conditions. The interfacial tension reduction, which was less than 1 mN/m, was evaluated using Tate's method. Additionally, the results obtained demonstrated that butanol exceeds laboratory experiences at a mere 20% concentration and enables maximum water recovery. The results of this work can be used to improve understanding of the trapped water phenomenon in water mixtures treated with alcohol and fractured reservoirs. [ABSTRACT FROM AUTHOR]

Purpose. Increasing oil recovery from deposits and reducing the water content of producing wells by providing conditions for uniform displacement of oil from the reservoir under the influence of high reservoir pressure. Methodology. The purpose of the work is achieved by conducting theoretical and experimental studies of the process of creating high elastic energy in the formation by pumping water with injection well pumps to overcome the resistance of oil and water filtration through the pores of the rock and oil rise at the mouth of producing wells. The absence of pumps from producing wells and the acceptance of equal amounts of injection and production wells over the reservoir area significantly increases the reservoir pressure above the pressure of oil saturation with gas. Due to the significant elasticity of the rock and fluids under high reservoir pressure, the oil coverage with water increases and there is no premature breakthrough of water into producing wells. The possibility of creating high elastic energy in an oil reservoir by pumping water into injection wells has been experimentally studied. Findings. It has been established that high reservoir energy in the field of elastic deformation of rock and fluids can be created mainly by pumps from injection wells, due to which oil is uniformly displaced from the reservoir along the entire front without breaking through the injected water into producing wells along the path of least resistance. The adoption of equal amounts of producing and injection wells and their sequential arrangement in rows contributes to the development of high potential energy in the reservoir and increase the pick-up rate of injection and production wells. As a result, the skeleton of the rock forming the pores expands, and the water injected into the reservoir and the displaced oil accumulate and increase reservoir energy. Originality. The effectiveness of the proposed method for maintaining high reservoir pressure is achieved as a result of creating high energy of rock and fluids in the area of their elastic deflation and increasing the coverage coefficients of oil displaced by water over the area and profile of the productive formation without the use of additional capacities and pumping units from producing wells. Practical value. The developed new technique for maintaining high elastic reservoir pressure not lower than the pressure of oil saturation with gas by pumping water into the reservoir can be carried out in oil fields using standard technological equipment and increase oil recovery to 60–70 % at its existing values of 40–45 % and reduce the water content of produced oil to 0–10 % at its existing values of 20–80 % and above. [ABSTRACT FROM AUTHOR]

AbstractThis research performed cellulase production by Aspergillus fumigatus A4112 and evaluated its potential use in palm oil mill effluent (POME) hydrolysis to recover oil simultaneously with the generation of fermentable sugar useful for biofuel production under non-sterilized conditions. Empty fruit bunch (EFB) without pretreatment was used as carbon source. The combination of nitrogen sources facilitated CMCase production. The maximum activity (3.27 U/mL) was obtained by 1.0 g/L peptone and 1.5 g/L (NH4)2SO4 and 20 g/L EFB at 40 °C for 7 days. High level of FPase activity (39.51 U/mL) was also obtained. Interestingly, the enzyme retained its cellulase activities more than 60% at ambient temperature over 15 days. In enzymatic hydrolysis, Triton X-100 was an effective surfactant to increase total oil recovery in the floating form. High yield of reducing sugar (50.13 g/L) and 21% (v/v) of floating oil was recoverable at 65 °C for 48 h. Methane content of the raw POME increased from 41.49 to 64.94% by using de-oiled POME hydrolysate which was higher than using the POME hydrolysate (59.82%). The results demonstrate the feasibility of the constructed process for oil recovery coupled with a subsequent step for methane yield enhancement in biogas production process that benefits the palm oil industry. [ABSTRACT FROM AUTHOR]

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The clay swelling is extremely harmful to the reservoir during tight oil and shale oil extraction. In order to prevent the interaction between clay and surfactants from making the clay to hurt reservoir during oil recovery, this paper studies the effects of different surfactants on reservoir clay. Clay-surfactant swelling experiments were conducted to observe the macroscopic effects of different surfactants on clay swelling and to summarize the rules, and molecular simulations were then used to explain this phenomenon. The results show that different surfactant groups have different tendencies to move toward the clay in water, with cationic groups moving toward the montmorillonite layers and anionic groups moving away from the montmorillonite layers, and nonionic does not have a significant effect. Cationic surfactant and amphoteric surfactant whose mechanism of inhibiting swelling action is directly reducing the negative electrical properties of the montmorillonite layers when Na+ outflow from montmorillonite layers, thus preventing electrostatic repulsion between montmorillonite layers to repel each other and move far away. In contrast, the nonionic surfactant, because it is not charged, cannot prevent the hydration of montmorillonite although there are surfactant molecules adsorbed on the layers due to van der Waals force; and the addition of anionic surfactant cannot suppress the negative electrical properties between the layers, which makes the diffusion of sodium ions between the layers augmented and promotes the swelling and dispersion of montmorillonite. This study is expected to provide benefits to oil production area by reducing the damage of surfactant imbibition fluid. [ABSTRACT FROM AUTHOR]

CO2 huff and puff is a widely used enhanced oil recovery method in many oil fields, but its implementations in shale fields is scarce. This paper reports trials of CO2 huff and puff in a shale field in China. Laboratory studies revealed that CO2 effectively reduced oil viscosity, increased oil volume, and improved oil recovery under miscible conditions. For the three wells that received CO2 huff and puff treatments, one well showed satisfactory results, while the other two wells demonstrated poor economics. Discussions and recommendations are made based on field experiences. © 2024 Society of Chemical Industry and John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

The article presents new results of laboratory studies, along with a summary of previously obtained ones. An analysis of the development of reserves in the experimental area was carried out with recommendations for improving the efficiency of its oil recovery processes in the amount of 10-30% of the pore volume of the experimental area. New conditions for injection with a limited supply of carbon dioxide are considered. The results of oil recovery modeling, using CO2 and water rims, are presented. The increase in oil recovery for reservoirs D1 and D2 was determined, and a forecast was made for the value of additional oil production per ton of carbon dioxide. [ABSTRACT FROM AUTHOR]

The application of titanium dioxide nanoparticles in the petroleum research area has received ample attention in recent years owing to its impact on wettability-altering agents. Further, employing a surfactant injection to improve oil production in sandstone formations on an industrial scale has become an alternative solution, particularly for mature fields. However, the existing literature on the combination of alkyl ethoxy carboxylate (AEC) surfactant with titanium dioxide nanoparticles on the application of enhanced oil recovery in sandstone formations remains underreported. This study explores the impact of combining AEC surfactant with titanium dioxide nanoparticles on recovering trapped oil in sandstone by examining the interfacial tension, contact angle, zeta potential, and core flooding with various concentrations of added titanium dioxide nanoparticles (0, 0.01, 0.025, and 0.05 wt%) on AEC surfactant. Although the addition of 0.05 wt% TiO2 to AEC surfactant can significantly reduce the interfacial tension to the lowest value of 5.85 × 10−5 mN/m, our results show that the highest oil recovery in Berea sandstone (59.52% recovery factor) is achieved at the concentration of 0.025 wt% added TiO2 to AEC surfactant. We find that the stability of TiO2 nanoparticles on AEC surfactant plays a significant role in getting maximum oil recovery. These important findings from this study contribute to improving our understanding on the application of TiO2 combined with AEC surfactant to achieve more efficient and sustainable enhanced oil recovery in sandstone.

Objective To achieve carbon peak and carbon neutrality goals, carbon dioxide flooding and storage are the main technical means for carbon emission reduction. It is crucial to clarify the main controlling factors of carbon dioxide flooding and storage under reservoir conditions, which provides the basis for realizing the efficient development of carbon dioxide flooding and storage. Methods In this study, with the widely used PUNQ-S3 case study as the basis, an integrated numerical simulation model of carbon dioxide flooding and geological storage is constructed. It considers the miscible interaction between carbon dioxide and crude oil as well as storage mechanisms, including structural, residual, dissolved, and mineral trapping. By employing the random forest intelligent algorithm, a feature importance analysis of reservoir and production parameters during the carbon dioxide flooding and storage process is carried out. The differences between carbon dioxide flooding and storage at different time scales are considered. A time series-based feature importance analysis method is established, and the main controlling factors in the different carbon dioxide flooding and storage stages are analysed. Through the fluctuation of the evaluation index, the influence of reservoir and production parameters on different stages of carbon dioxide flooding and storage is inferred. Results The results show that the time series-based random forest model for carbon dioxide flooding and storage has high accuracy. In the early stage of carbon dioxide flooding and storage, the amount of carbon dioxide structural storage is controlled by the reservoir water saturation, and the amount of dissolved storage is controlled by the salinity of the formation brine; In the middle and later stages of carbon dioxide flooding and storage, the amount of carbon dioxide structural storage is controlled by reservoir permeability, while the amount of dissolved storage is controlled by reservoir permeability and formation water salinity; The residual storage capacity is small in the early stage of carbon dioxide flooding and storage, resulting in unclear main controlling factors.In the later stage of carbon dioxide flooding and storage, it is controlled by reservoir permeability and water saturation; The amount of mineralization storage is controlled by the pH value and the salinity of the formation brine throughout the entire CO2 flooding and storage stage; The amount of carbon dioxide production is controlled by reservoir permeability and water saturation throughout the entire carbon dioxide flooding and storage stage. Conclusion The time-series-based random forest algorithm can identify the main controlling factors of different carbon dioxide flooding and storage stages and can provide support for cimproving crude oil recovery and implementing efficient geological storage with carbon dioxide.

Porous carbonate reservoirs are characterized by strong heterogeneity and diverse pore types， with significant differences in waterflooding recovery and unclear main controlling factors. Based on the pore throat size distribution curves， the microscopic pore structure of the reservoir was qualitatively classified. Through digital core technology， a method for quantitative characterization of microscopic pore structure was established to clarify the pore throat characteristics of porous carbonate rocks in a region of the Middle Eastern， and indoor physical experiments on waterflooding were conducted to clarify the differences in the oil recovery of different types of cores and their main controlling factors. The results show that ① The microscopic pore structure of the reservoir in the study area can be classified into coarse unimodal type， fine unimodal type I， fine unimodal type II， coarse bimodal type， and multimodal type. There is no significant relationship between storage performance and core homogeneity； the single-phase flow capacity of non-unimodal type is better than that of unimodal type； unimodal type becomes worse with increasing core homogeneity. ②The average coordination number and pore-throat ratio of the non-unimodal type are higher than those of the unimodal type. The average coordination number and pore-throat ratio decreased with the increase of core homogeneity for the unimodal type. The upper limit of the pore-throat ratio tends to decrease with increasing throat radius for all types， and the upper limit of coordination number increases exponentially with increasing pore radius. ③Macroscopically， core homogeneity is the main controlling factor of oil displacement efficiency； microscopically， high connectivity at large pore-throat and large pore-throat ratio at small pore-throat are the fundamental reasons for non-unimodal type to have significantly lower oil displacement efficiency than unimodal type. Pore-throat size is the crucial factor of oil displacement efficiency of unimodal type.

Spent bleaching earth (SBE) waste generated from crude palm oil (CPO) processing companies is constantly increasing as the demand for the oleo product is rising worldwide. This study aims to assess oil recovery from SBE using two process options to be implemented in a cooking oil plant in Sei Mangkei, North Sumatra. A techno-economic simulation was conducted to assess the feasibility of the two scenarios. The first scenario of the oil recovery plant from SBE was proposed without bleaching earth (BE) recovery. The second scenario proposed both oil and BE recovery. The research results showed that both scenarios were feasible, with scenario 2 having slightly better economic parameters. The SBE volume processed by the company was far more significant in affecting the feasibility of SBE reutilization. According to the techno-economic calculations, in scenario 1, the internal rate of return (IRR) was 23.56 %, the net present value (NPV) was USD 2.6 million, and the payback period was 3.9 years. Scenario 2 exhibited an IRR of 25.21 %, an NPV of USD 3.375 million, and a return time of 3.7 years.

New approaches to low salinity water (LSW) injection methods, such as LSW/surfactant, LSW/polymer, and LSW/nanofluid flooding, have been studied for oil reservoirs. Numerous researchers discussed the mechanisms related to enhanced oil recovery (EOR) efficiency and highlighted the significant impact of the wettability alteration and interfacial tension (IFT) reduction. This work studied the effect of exposure time on the wettability alteration and IFT in the LSW/nanoparticle (LSWN) flooding. Contact angle tests investigated rock wettability over a series of different times. A pendant drop tensiometer was used to measure the IFT. By coreflood apparatus, waterflood tests were also conducted, considering the effect of soaking time. Laboratory results showed that the involved mechanisms are time-dependent. More water-wet conditions and higher oil recovery were obtained under longer soaking time. In addition, the positive effect of LSWN was observed in tertiary flooding tests. The results also indicate that the effect of water-soluble oil compounds should be considered in measuring wettability and IFT. [ABSTRACT FROM AUTHOR]

The use of surfactants in oil recovery can effectively improve crude oil recovery rate. Due to the enhanced salt and temperature resistance of surfactant molecules by non-ionic chain segments, anionic groups have good emulsifying stability. Currently, there are many studies on anionic non-ionic surfactants for oil recovery in China, but there is relatively little systematic research on introducing EOs into hydrophobic alkyl chains, especially on their self-assembly behavior. This article proposes a simple and effective synthesis method, using 3-aminopropane sulfonic acid, fatty alcohol polyoxyethylene ether, and epichlorohydrin as raw materials, to insert EO into hydrophobic alkyl chains and synthesize a series of new anionic non-ionic Gemini surfactants (CnEO-5, n = 8, 12, 16). The surface activity, thermodynamic properties, and self-assembly behavior of these surfactants were systematically studied through surface tension, conductivity, steady-state fluorescence probes, transmission electron microscopy, and molecular dynamics simulations. The surface tension test results show that CnEO-5 has high surface activity and is higher than traditional single chain surfactants and structurally similar anionic non-ionic Gemini surfactants. Additionally, thermodynamic parameters (e.g., ΔG°mic ΔH°mic ΔS°mic et al. indicate that CnEO-5 molecules are exothermic and spontaneous during the micellization process. DLS, p-values, and TEM results indicate that anionic non-ionic Gemini surfactants with shorter hydrophobic chains (such as C8EO-5) tend to form larger vesicles in aqueous solutions, which are formed in a tail to tail and staggered manner; Negative non-ionic Gemini surfactants with longer hydrophobic chains (such as C12EO-5, C16EO-5) tend to form small micelles. The test results indicate that CnEO-5 anionic non-ionic Gemini surfactants have certain application prospects in improving crude oil recovery. [ABSTRACT FROM AUTHOR]

Sweep efficiency of stagnant and poorly drained reservoir zones is extremely relevant task during gas and chemical flooding of hard-to-recover reserves. The paper presents the results of the field implementation of the in-situ CO2 generation technology to recovery of residual oil reserves and increase the sweep efficiency factor. The article presents the results of theoretical and laboratory studies, as well as field cases of an energy- and resource-saving method for oil recovery increase and improving oil production. The results of the reservoir stimulation confirmed the increase in the total incremental oil production after treatment operation on recovering residual oil reserves on. [ABSTRACT FROM AUTHOR]

Due to the deterioration of the structure of oil reserves, the demand for enhanced oil recovery technologies is increasing every year. These technologies are usually classified into the following: Chemical, gas, thermal and combined enhance oil recovery methods. Among the chemical methods, polymer flooding stands out. It has been actively studied since the middle of the last century and currently numbers hundreds of completed projects around the world. Despite the relatively long study period and the number of publications dedicated to polymer flooding, there is still a range of aspects requiring research and development as well as field testing. One of the crucial issues at the preparation stage of a polymer flooding project is necessity to select oilfield or pilot area to achieve the best possible technological and economic efficiency results. This article provides analysis of the key factors influencing effectiveness of polymer flooding implementation. The paper reflects historical evolution, i.e. expansion of the technology applicability limits. Their current values have been verified, based on the analysis of the experience of implementing the technology in extreme conditions. Applicability criteria has been established as well for the polymer flooding development. The paper includes development of a uniquely designed integrated methodology for screening, assessment and ranking of promising objects for the technology implementation. The methodology is designed on the basis of a background review of completed projects, as well as on the expertise of the specialists involved in the development and scientific support of chemical enhanced oil recovery projects implementation. The purpose of the methodology is to create a basic universal tool for an express assessment of the prospects for using polymer flooding in different fields, which a wide range of specialists in the oil and gas industry could apply. [ABSTRACT FROM AUTHOR]

It is of great importance to select appropriate chemicals and synthetic methods in oilfield applications. In this review, various synthetic routes for preparation of fluorinated surfactants were described and their oilfield applications were highlighted. Fluorinated surfactants are a special type of surfactants whose hydrophobic tails are either partially fluorinated or totally replaced with fluorine atoms. Compared with corresponding hydrocarbon surfactants, fluorinated surfactants have distinct properties such as lower surface tension, better efficiency in lowering the interfacial tension, with the fluorocarbon chain being both oleophobic and hydrophobic and exhibiting high thermal stability and better chemical durability. These properties make them ideal materials in many applications, including firefighting, household items, foaming, coating, paints, etc. Despite these attractive properties, environmental concerns associated with fluorinated surfactants have greatly restricted their application. Herein, the synthetic routes for different classes of fluorinated surfactants such as cationic, anionic, nonionic, and zwitterionic ones were discussed. The fundamental surface/interfacial activities of the synthesized surfactants were described. In addition, the applications of fluorinated surfactants in the oil & gas industry were highlighted. [ABSTRACT FROM AUTHOR]

This paper explores the crucial factors influencing the stability of polymer gels utilized in oil well treatments, with a focus on the effects of polymer mixing time and concentrations of polymer and crosslinker. Operating within a practical constraint of a 30-minute mixing time in surface facilities, our findings reveal that incomplete polymer dissolution leads to gel segregation and substantial water release over extended aging at 50 ºC. Notably, a reduction in the crosslinker/ polymer ratio, achieved by lowering crosslinker concentration or increasing polymer concentration, proves effective in mitigating water release to as low as 0--1% over 90--185 h of aging. Furthermore, gels prepared in sea and reservoir brines exhibit superior stability compared to those in distilled water, suggesting that ion presence in brines counteracts the repulsion between charged polymer chains observed in distilled water. This study provides valuable insights for optimizing polymer gel formulations under time constraints. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

This study aims to explore the influence of screw frequency, nozzle diameter, and press head temperature on critical crude fodder radish seed oil (FRSO) yield, throughput, and fatty acid composition. A quadratic equation, developed using response surface methodology, fitted the experimental data for oil yield. It was substantiated by a non‐significant lack‐of‐fit, commendable coefficient‐of‐determination (R2 = 0.782), and a modest mean relative percentage deviation (±7.27%). The analysis of variance pinpointed the statistical significance of press head temperature, nozzle size, and the squared term of press head temperature. The highest FRSO yield (17.61%)—corresponding to an extraction efficiency of 51.3% was found with a screw frequency of 50 Hz, at 80°C, and an 8 mm nozzle. A linear model highlighted that all three pressing factors significantly influenced the FRSO throughput. FRSO consists of C18:1 (30.9%), C22:1 (20.8%), C18:2 (14.9%), and C18:3 (11.9%), aligning with the compositions reported in other studies on fodder radish oils. Practical applications: Effective control of cold pressing parameters is paramount to maximize oil yield and throughput during the oil extraction process and to ensure the appropriate oil quality. A comprehensive understanding of the intricacies of this process, while carefully considering key parameters, which is essential to ensure efficiency, is achieved through a combination of experimental and statistical methods. This study marks the inaugural attempt to optimize screw pressing for fodder radish seeds while conducting a comparative analysis with hydraulic pressing and the Soxhlet extraction method, focusing on oil yield, throughput, and fatty acid composition within the system by employing a modeling approach for oil extraction. Through the utilization of the response surface methodology coupled with various experimental designs, the processing conditions are successfully optimized. The valuable data gathered can aid equipment design for an efficient, eco‐friendly oil extraction process. Furthermore, the oil extracted under the optimized conditions met the quality standards. [ABSTRACT FROM AUTHOR]

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Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

This paper explores the crucial factors influencing the stability of polymer gels utilized in oil well treatments, with a focus on the effects of polymer mixing time and concentrations of polymer and crosslinker. Operating within a practical constraint of a 30-minute mixing time in surface facilities, our findings reveal that incomplete polymer dissolution leads to gel segregation and substantial water release over extended aging at 50 ºC. Notably, a reduction in the crosslinker/ polymer ratio, achieved by lowering crosslinker concentration or increasing polymer concentration, proves effective in mitigating water release to as low as 0‒1% over 90‒185 h of aging. Furthermore, gels prepared in sea and reservoir brines exhibit superior stability compared to those in distilled water, suggesting that ion presence in brines counteracts the repulsion between charged polymer chains observed in distilled water. This study provides valuable insights for optimizing polymer gel formulations under time constraints.

Abstracts: Steam injection is commonly used for production of viscous crude oil. Reservoir rock often contains clay minerals. Reactive nature of steam and clay minerals may lead to formation damage. This work investigates oil recovery and changes in petrophysical properties as a function of the mineralogy. Sandpacks with quartz, calcite, feldspar, kaolinite, smectite, and illite were prepared for steam injection experiments. Permeability of the steamed sandpacks was determined using coreflood experiments. Chemical composition of the produced aqueous samples was determined using ICP-OES (inductively coupled plasma-optical emission spectroscopy). Morphology of the rock samples was studied using SEM-EDS (scanning electron microscope-energy dispersive X-ray spectroscopy). Mineralogy and elemental content of the solid samples were determined using XRD (X-ray diffraction) analysis and XRF (X-ray fluorescence) respectively. It was found that aqueous phase samples produced from clay-rich sandpacks tend to have higher pH than samples produced from samples without clay minerals. Oil recovery factors for 100% quartz case was determined to be 65 wt%. Calcite- and feldspar-rich sandpacks produced 56 and 61 wt% of oil respectively. Sandpacks with clay fractions have shown the lowest oil recovery – 39, 29, and 28 wt% for kaolinite-, smectite-, and illite-rich samples respectively. Mineral dissolution and precipitation were the dominant damaging mechanism for quartz and calcite cases. Feldspar-rich sandpack demonstrated signs of structural destruction of the mineral and fines release. Kaolinite's effect on oil recovery was found to be associated with fines migration. Smectite hydration and swelling in presence of steam was the dominant formation damage effect on the oil production. Steam interaction with illite-rich sandpack caused formation of amorphous silica. This paper presents oil recovery factors as a function of injected pore volume (PV) of steam for sandpacks of different mineralogy. Obtained results characterize petrophysical changes caused by steam interaction with minerals in presence of oil. This data provides insights into effects of steam on minerals with different structures and properties.

Low salinity water flooding (LSW) has been proven to be a low-cost and accessible enhanced oil recovery method in conventional reservoirs. However, its applications and potentials in tight reservoirs are mysterious in tight sandstone reservoirs due to the low porosity and low permeability.A series of laboratory experiments were designed to investigate ionic composition and salinity on the performance of LSW in a tight oil formation. More specifically, zeta potential and contact angle were measured to examine rock surface charge distribution and wettability changes. Pressure-controlled mercury injection (PMI) and permeability tests were conducted to analyze the pore & throat and permeability changes during LSW injection. Thereafter, displacement experiments were implemented to analyze oil recovery under different LSW injection schemes.The experimental observation demonstrates that LSW injection expands the double electric layer on the oil/brine and rock/brine interfaces, resulting in the expected wettability modification. However, the presence of divalent ions in the LSW undermines this effect. On the other hand, the permeability reduction resulting from salinity decrease can be alleviated by introducing divalent ions into LSW. The coreflooding experiments reveal that continuous injection of monovalent brine would reduce the ultimate oil recovery. Alternatively, a mixture of monovalent and divalent ions in LSW is utilized to revive the permeability and maintain the wettability modification. Furthermore, an optimized lower divalent ion concentration is found to be conducive to refining the cutoff throat radius and achieving a higher oil recovery from tight oil reservoirs.

Controlled salinity water flooding also known as engineered water flood has been tested as a potential enhanced oil recovery (EOR) method in laboratory as well as at pilot/field scale. However, there are cases seen where the method has failed to show its potential for EOR. Scientists believe that the lack of understanding of case specific underlying mechanism is the primary reason. Many of the literatures claims reduction of interfacial tension as the primary oil recovery mechanism; but recent findings highlighted that modification of electrical charges on rock surface with response to injection brine salinity has greater effect. In order to investigate the same and in search of more insightful mechanism, in this study we have designed and performed experiments with selected chemicals which can modify surface properties of sandstone and also the oil water interfacial tension. The electrical charge of the rock surface and oil–brine​ interfacial tension were modified by tuning salinity of injection water and adding surfactants (sodium dodecyl benzene sulfonate, SDBS and cetyltrimethylammonium bromide, CTAB). The electrical charge of the sandstone surfaces was quantified with zeta potential measurement. The oil recovery potential of the injection fluids was tested through laboratory core flooding experiments at controlled near reservoir conditions. Superposition of all the obtained results revealed that low salinity injection brine modifies the sandstone surface to higher negatively charged state than high salinity water. Therefore, with a negatively charged oil–brine interface it causes strong repulsive forces promoting detachment of residual oil and subsequent mobilization. The hypothesis is also proved by the fact that SDBS in spite of resulting in a lower interfacial tension reduction than CTAB yielded higher oil recovery. This is because of the negative zeta potential caused by SDBS to sandstone surface in comparison to the positive zeta potential observed in the case of CTAB.