Oil Recovery Research Articles

Preparation of styrene‐phenylamine monomer copolymer nanospheres and its performance for stabilizing CO2 foam

AbstractImproving the stability of CO2 foam is a core concern in CO2 foam flooding oil recovery technology. Using hydrophobic nano‐SiO2 to enhance the stability of CO2 foam is a common approach, but hydrophobic nano‐SiO2 faces challenges, such as easy aggregation, difficult dispersion, and performance needs to improve. In this article, a novel dispersion of styrene‐phenylamine monomer copolymer (PSSN) nanosphere with primary amine groups on the surface was synthesized. The synthesis conditions of PSSN were optimized, and its performance for stabilizing CO2 foam was evaluated. The experimental results demonstrated that PSSN had better performance for stabilizing CO2 foam than that of hydrophobic nano‐SiO2 when using cocamidopropyl betaine (CAB) as the foaming agent. With the CAB concentration of 4000 mg/L and PSSN concentration of 100 mg/L in the brine having salinity of 8460 mg/L, the half‐life of CO2 foam at 90°C was 131 min, which was 43 min longer than that stabilized by hydrophobic nano‐SiO2 under the same conditions. This is for the first time that polystyrene microspheres with amine groups on the surface was used to stabilize CO2 foam. The study provides a new nanoparticle option for stabilizing CO2 foam.

Unraveling the adsorption dynamics of asphaltene molecules on silica surfaces

Understanding the adsorption behavior of heavy oil components on reservoir solids is crucial for improving oil recovery, yet the molecular mechanism remains unclear. This study used molecular dynamics simulations to explore the adsorption kinetics and thermodynamics of asphaltene molecules on silica surfaces. The adsorption process was divided into three stages: free, adsorption, and equilibrium. In the adsorption stage, asphaltenes must pass through two dense hydration layers and adhere to the silica surface in a flat configuration. Carboxyl groups increase asphaltene hydrophilicity, raising interaction energy with water molecules and hindering adsorption. In addition, two distinct hydration layers of water molecules on the silica surface. The first hydration layer, with a peak density of 2000 kg m−3, was located around 0.6 nm from the surface, driven by hydrogen bonding between Si-OH groups and water molecules. The second layer, found at 1.44–1.80 nm, had a lower density of 1200 kg m−3, formed through hydrogen bonding between water molecules. This study aims to enhance the understanding of the physicochemical mechanisms governing oil droplet adsorption on silica surfaces, potentially informing the design of improved oil recovery strategies.

Synthesis and Characterization of Self-Dispersion Monodisperse Silica-Based Functional Nanoparticles for Enhanced Oil Recovery (EOR) in Low-Permeability Reservoirs

A controllable particle size mono-dispersing nanofluid system has been developed to address the challenges of low porosity and low-permeability in low to ultra-low-permeability reservoirs. This system combines high dispersion stability with enhanced oil recovery performance, and its effectiveness in improving recovery rates in low-permeability reservoirs, where conventional chemical flooding is ineffective, has been well demonstrated. Using the in situ method to prepare monodispersed nano-silica particles, the effects of the water concentration, ammonia concentration, and silica precursor concentration on the morphology, particle size, and formation time of the silica spherical particles were analyzed. Building on this foundation, a partially hydrophobic modified nano-silica oil displacement fluid was synthesized in situ. The system’s dispersion stability, ability to reduce oil-water interfacial tension, and capacity to alter rock wettability were evaluated. Core physical models were used to evaluate the oil displacement efficiency and the permeability applicability limits of the self-dispersing nano-silica oil displacement system. The experiments confirmed that the particle size distribution of the self-dispersing nano-silica oil displacement system can be controlled within a range of 10 nm to 300 nm. The nanofluids exhibited excellent stability, effectively altering the rock wettability from oil-wet to water-wet and reducing the oil-water interfacial tension to approximately 10−1 mN/m. The nano-displacement system increased the recovery rate of the low permeability reservoirs by more than 17%. The in situ modification method used to prepare these self-dispersing nanoparticles provides valuable insights for synergistic enhancement of recovery when combined with other systems, such as surfactants and CO2. This approach also opens up new possibilities and drives further development in the field of nano-enhanced oil recovery chemistry.

CO 2 geological storage potential in the Croatian part of the Pannonian Superbasin

In the continental part of Croatia, oil and gas have been discovered in more than 60 locations. Most reservoirs are in the Neogene/Quaternary basin infill, but the largest ones are found in the basement rocks. Decades of exploration have left a significant vintage dataset and substantial knowledge of the subsurface geology and reservoir properties. Since 2005, research efforts have been redirected towards CO 2 geological storage capacity estimates, and the first results were obtained relatively quickly. All identified potential storage objects – deep saline aquifers, depleted hydrocarbon fields and oil reservoirs that are suitable for CO 2 enhanced oil recovery (CO 2 -EOR) – can be regarded as prospective. The deep saline aquifers are defined on a regional scale and their estimated capacity is the highest (2584 Mt), but this is ‘theoretical capacity’ that can only be used to outline the total resource base. The storage capacity estimated for the selected 14 depleted hydrocarbon fields sums to 143.6 Mt, and this is a viable capacity that might be developed as soon as a particular field stops with production, but the most promising storage objects are the seven fields that have reservoirs suitable for CO 2 -EOR operations. The most recent models have revealed that seven active EOR fields operating in parallel between 2025 and 2040 could store up to 1.2 Mt CO 2 a −1 , while producing c. 1.2 Mt a −1 of additional oil. This is very high for a country with only 5.5 Mt CO 2 a −1 in point sources.

Dynamic Adsorption and Oil Recovery of Nanosilica on Carbonate Rock.

Numerous studies have investigated the use of nanosilica particles for enhanced oil recovery (EOR). Many of these studies focused on experiments involving LHP (lipophobic and hydrophilic polysilicones) and HLP (hydrophobic and lipophilic polysilicones) in water-wet sandstones and oil-wet carbonate rocks. This paper's gap investigates comparing LHP and HLP nanosilica particles in enhancing oil recovery in water-wet and neutral-wet carbonate rocks. Additionally, the effects of LHP and HLP adsorption during injection and their influence on oil recovery have not yet been extensively investigated. This study used Sumatran crude oil from Indonesia, and to support the objectives of this study, several analyses were conducted, including measurements of rock wettability, interfacial tension, fluid stability, zeta potential, UV-vis spectrophotometric adsorption, and coreflood injection as the main experiment under different scenarios. The findings demonstrate that the oil recovery enhancement is influenced by the type of nanosilica used. Specifically, LHP nanosilica exhibited higher oil recovery in neutral-wet carbonate rocks, about 9.78-44.44%, while HLP nanosilica showed better performance in water-wet carbonate rocks in the range of 4.11-41.01% in different injection scenarios. Moreover, a directly proportional relationship was observed between the adsorption of LHP and HLP nanosilica on the rock and fluid and oil recovery, where increased adsorption corresponded to higher oil recovery for each injection scenario with the respective type of nanosilica about 0.06-0.15 mg/g. These results provide valuable insights into selecting the appropriate nanosilica and initial wettability conditions in EOR applications.

Probing the Behaviour of Fluids Confined in Porous Materials by Neutron Scattering: Applications to CO2 Sequestration and Enhanced Oil and Gas Recovery.

The current review presents a discussion on the utility of neutron scattering, with emphasis on neutron total scattering and small-angle neutron scattering (SANS), to explore the structural properties and the phase behaviour of fluids confined in nanopores. The effectiveness of contrast matching SANS on the evaluation of accessibility of porous materials to invading fluids is highlighted too. This review provides also an overview regarding the neutron scattering studies on the structure and the accessibility of greenhouse gases in the complex pore network of geomaterials, with applications to CO2 geological sequestration and enhanced oil and gas recovery.

Study of Phase Separation and Reversibility in CO2-Responsive Superamphiphile Microemulsions.

Phase separation of microemulsions occupies a key position in many applications, such as oil recovery, nanomaterial synthesis, and chemical reactions. Achieving an intelligent response is crucial to microemulsion development and application. For this reason, in this study, CO2-responsive superamphiphilic molecules were developed as rapidly switchable oil-in-water microemulsions. These superhydrophilic molecules with linear structures were produced by electrostatic interaction of stearic acid and aminotrimethyltriazine COSM-1 in a 1:1 molar ratio. The introduction of n-butanol as a cosurfactant in the CO2-responsive microemulsion system resulted in the spontaneous formation of stable microemulsions. The effect of the addition of n-butanol on the carbon dioxide-responsive microemulsion system was investigated, and the optimum amount of n-butanol was determined by optimization. After exposure to CO2 for 30 s, the superhydrophilic molecules decomposed into inactive components at the interface, leading to a complete phase separation of the microemulsion into oil and water phases. The system was purged with N2 at 60 °C for 10 min to remove the CO2, and the phase separation system was transformed into a clear microemulsion, which was then evaluated for its properties. The rapid response and complete demulsification of these surface CNFS superamphiphiles to CO2 suggest that they have promising applications in product separation, microemulsion recovery, and enhanced crude oil recovery.

Hydrophilic Chain Length for Octylphenol Polyoxyethylene Ether Adsorption at the n-Hexadecane-Water Interface: Theoretical and Experimental Study.

With the advancement of technologies for developing tight and shale reservoirs, nonionic surfactants have garnered significant attention due to their remarkable properties. The structure of these surfactants plays a crucial role in determining the characteristics of the oil-water interface, particularly influencing emulsification behavior and crude oil recovery. This study investigates the effect of varying the number of hydrophilic polar groups (n = 10, 20, 30, 50) in octylphenol polyoxyethylene ether (OP-n) on its adsorption behavior at the n-hexadecane-water interface using molecular dynamics simulation. The impact of these variations on interfacial properties was further analyzed through measurements of interfacial tension and observations of emulsion droplet morphology. The study results indicate that variations in the number of hydrophilic polar groups significantly affect interfacial properties. Increasing the number of hydrophilic polar groups led to a notable increase in the thickness of the n-hexadecane or water phase, as well as the thickness of the water or oil layer and the surfactant layer. Moreover, when the number of hydrophilic polar groups reached 20, the OP-n molecules exhibited a more curled conformation at the interface, enhancing their ability to encapsulate water and resulting in a decrease in the diffusion coefficient of the molecules in each phase. Additionally, interfacial tension was found to be positively correlated with the number of hydrophilic polar groups and remained unchanged beyond a certain emulsion diameter. This study provides a theoretical basis and reference data for optimizing surfactant structures to improve crude oil recovery.

Carbon footprints of centralized and decentralized food waste utilization pathways

Food waste is usually utilized in centralized treatment facilities and is sometimes treated in decentralized facilities; however, the latter has not been evaluated systematically regarding carbon emissions. This study surveyed fifty-nine centralized and decentralized food waste treatment projects in Shenzhen, and incineration, anaerobic digestion, composting, and emerging technologies such as insect bioconversion and organic acid production were applied. Their carbon footprints were analyzed based on real data covering collection and transport, energy and material consumption, secondary pollutant control, and impurity disposal. The results showed that centralized facilities had a lower overall carbon footprint, although carbon emissions from their collection and transportation were higher. Anaerobic digestion performed best with an average carbon emission of −136.63 kg CO2-eq/t, followed by black soldier fly larvae cultivation (−12.86 kg CO2-eq/t), incineration (−11.02 kg CO2-eq/t), and organic acid production (−6.86 kg CO2-eq/t). All decentralized facilities were operated with net carbon emissions because they consumed a large amount of electricity or thermal heat without the full use of organic matter in the food waste. An optimal route was recommended by combining centralized anaerobic digestion and decentralized squeezing dewatering with adequate oil recovery, and this can make the overall carbon emission decrease from −6.72 kg CO2-eq/t to −17.75 kg CO2-eq/t. These results can provide decision-makers with guidance on food waste management to support net zero and sustainable development goal 12 and 13.

Fractional Flow Analysis of Foam Displacement in Tight Porous Media with Quasi-Static Pore Network Modeling and Core-Flooding Experiments

Fractional flow analysis is an efficient tool to evaluate the gas-trapping performance of foam in porous media. The pore-scale simulation study and the core-scale experimental work have been bridged via the fractional flow analysis to distinguish the characteristics of foam displacement inside the tight porous media with varying absolute permeability, injection rate, and foam quality. In this work, the combined investigation suggests that conventional foam-enhancing strategies, pursuing higher foam quality and stronger foam regime, are inefficient and restricted in tight reservoirs that the critical Sw corresponding to the limiting capillary pressure has increased around 37~43%, which indicates severely weakened gas-trapping capacity as permeability reduces one order of magnitude. The moderate mobility adjustment and corresponding optimized fluid injectivity exerting from the “weak foam” flow presents a staged decline feature of decreasing water fractional flow, which implies the existence of the delayed gas-trapping phenomenon when water saturation reduces to 0.5~0.6. The finding has supported the engineering ideal of promoting low-tension gas (LTG) drive processes as a potential solution to assist field gas injection applications suffering from gas channeling. Also, the validation with core-flooding experimental results has revealed several defects of the current pore network model of foam displacement in tight porous media, including exaggerated gas trapping and overestimated confining water saturation. This study has innovatively demonstrated the feasibility and potential of optimizing the foam performance of gas trapping and mobility control in tight reservoirs, which provides a clue that may eventually boost the efficiency of the gas injection process in enhanced oil recovery or CO2 sequestration projects.

Study on interfacial tension, wettability and viscosity in different salinities of synthesized a new polymeric surfactant for improving oil recovery

Over 50% of the original oil in place (OOIP) is immobile or trapped in the reservoir. Therefore, today, more efficient methods have been introduced in the tertiary oil recovery sector as a scheme of enhanced oil recovery (EOR). Due to the decline of conventional hydrocarbon reserves, polymers are increasingly used in EOR methods, such as surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding. SP flooding has a complex formulation and design, leading to undesirable phase separation if improperly mixed. Polymeric surfactants are a promising alternative to SP flooding. They consist of hydrophobic groups attached to hydrophilic polymers, which help to improve the mobility ratio and reduce interfacial tension (IFT). This paper examines the rheological and synthesis properties of a new polymeric surfactant produced through bond co-polymerization reaction using different hydrolyzed polyacrylamide (HPAM) ratios and a zwitterion hydrophobic group. The synthesized hydrophobically modified zwitterionic polyacrylamide (HMZPAM) was characterized by FTIR and HMNR analysis. HMZPAM performed better than other substances in IFT, viscosity, wettability, oil recovery, and resistance to different one and two-valence cations. The results indicate that HPAM reduced the IFT to 13.65, while HMZPAM reduced it to 0.441 mN/m. Wettability change evaluated on a rock carbonate/crude oil/HMZPAM system that changed the water-wet state of the primary oil-wet rock carbonate to strongly water-wet state as wettability change measurements showed a decrease in contact angle from 62.76 to 21.23 degree. Comparative studies on the effectiveness of HPAM and HMZPAM were also conducted according to the measurement of viscosity and shear rate in the presence of salt, which indicates the higher shear rate and viscosity of HMZPAM. Core flooding tests revealed that HMZPAM resulted in better additional recovery due to microscopic displacement, resulting in a total oil recovery of 84%, compared to 48% of residual oil saturation for HPAM. Also, salts decreased oil recovery in HPAM injection but increased oil recovery in HMZPAM injection.

Emulsification and interfacial characteristics of different surfactants enhances heavy oil recovery: experimental evaluation and molecular dynamics simulation study

The high viscosity and poor fluidity of heavy oil challenge its extraction, leading to the widespread use of surfactant emulsification to reduce viscosity and enhance recovery. This study evaluated three surfactants—sodium dodecyl sulfate (SDS), sodium oleate (SO), and APG0810—for their suitability and effectiveness in the X reservoir. The solution properties of these surfactants were analyzed and their micro-mechanisms investigated using MD calculations. The effects of surfactant concentration and additives on emulsification and viscosity reduction were elucidated. Ultimately, a system for emulsification and viscosity reduction was selected for physical simulation research. The experimental findings show that SO reduces interfacial tension from 52.4 mN/m to 0.0027 mN/m, transforming lipophilic surfaces into hydrophilic. MD analyses reveal SO’s optimal interfacial properties, with the lowest interfacial energy of −6423.4 kcal/mol, maximum interfacial thickness of 2.56 nm, and minimal diffusion coefficient of 0.4087 Å2/ps at the oil-water interface. These findings align with experimental results, confirming SO’s superior interfacial properties. Combining 0.3% SO with 0.5% n-pentanol results in a 98% viscosity reduction. The emulsion shows excellent stability, with no water separation in the first 30 min and only 8.3% after 2 h. Physical simulation results show that in high(low) permeability core displacement experiments, system flooding and subsequent water flooding can increase recovery rates by 15.39%(36.91%), indicating the system’s potential for enhancing oil recovery in Reservoir X. The findings suggest that the implementation of this system not only boosts the crude oil recovery rate but also carries economic significance in the industry.

Investigation of drive mechanisms in fractured oil reservoirs with tight matrix: a case study of an Iranian reservoir

ABSTRACT Tight matrix oil reservoirs pose significant challenges for oil recovery due to their low permeability and intricate fracture networks. Effective reservoir development strategies require a thorough understanding of the recovery mechanisms; otherwise, it is difficult to maximize production rates and optimize the oil recovery factor. The reservoir examined in this study contains black oil within a tight matrix, complicating the planning and selection of appropriate recovery methods. Despite strong bottom water influence and high water-cut issues, the fractures in the reservoir facilitate economical extraction. However, the reservoir’s complexity, coupled with limited knowledge and experience in this area, further complicates recovery efforts. In this study, we investigated the multi-mechanistic flow dynamics within the porous media. Simulation results indicate that during the first month of production, the dominant recovery mechanism is rock expansion drive. Beyond this period, the water drive mechanism prevails. Over a ten-year period, oil recovery is distributed as follows: 13.1% from bottom water drive, 1.0% from gas cap drive, 0.2% from rock expansion, and 0.6% from oil expansion drive.

Construction and Properties Evaluation of the Binary Flooding System Based on Lipid Peptide.

To enhance crude oil recovery under complex reservoir conditions and reduce the environmental impact of the oil displacement system, a biosurfactant lipid peptide (TH) was combined with four chemical surfactants. From these combinations, those capable of achieving an ultralow interfacial tension region (<10-2 mN/m) were selected. The selected surfactant mixtures were then combined with polyacrylamide (HPAM) to construct a surfactant-polymer binary oil displacement system. The results showed that TH/OAB(2:1), TH/OAB(3:1), and TH/EAO(3:1) could reduce IFT to the ultralow interfacial tension region. Compound surfactants are easier to form mixed micelles than single surfactants, and the EACN of TH/OAB(2:1) and TH/EAO(3:1) is consistent with EACNOil, which can achieve higher surface activity at lower concentrations. The three compound surfactants have a wide range of ultralow interfacial tension concentrations and excellent antidilution performance. TH/OAB(2:1) and TH/EAO(3:1) have better antiformation adsorption performance than TH/OAB(3:1), and the oil washing rate of TH/OAB(2:1) is up to 80.30%. TH and OAB have spatial complementarity, which can increase the molecular packing density at the oil-water interface and reduce the IFT. In CaCl2 and NaCl solutions, the IFT of the two binary flooding systems constructed by TH/OAB(2:1) and TH/EAO(3:1) and HPAM remained in the ultralow interfacial tension region, with excellent salt resistance. When aged in the reservoir for 90 days, the IFT slightly increased but the viscosity decreased significantly. Adding a viscosity retaining agent (JW) was required to maintain the viscosity of the system. In the simulated oil displacement experiment, the recovery improvement of the two binary oil displacement systems was higher than those of surfactant and polymer alone. This study provides a new idea for the alkali-free surfactant-polymer binary oil flooding system and provides theoretical support for the practical application of TH in tertiary oil recovery.

Synthesis and surfactant properties of sulfonate Gemini surfactants

Abstract In this study, a novel high salinity resistant, high temperature tolerant sulfonate Gemini surfactant (CK-3) for enhanced oil recovery was synthesized and is described. The critical micelle concentration (CMC) of CK-3 is 7.3 × 10−5 mol L−1 with a surface tension at CMC, γ CMC , of 30.88 mN m−1, and a pC20 value of 4.80. Moreover, increasing temperature led to delayed micellization, indicating the superior surface activity inherent in Gemini surfactants. When CK-3 was evaluated as an imbibing agent, an interfacial tension of 8.3 × 10−2 mN m−1 was observed between a 0.3 wt% CK-3 solution and crude oil, facilitated by hydrophobic group interactions which allow crude oil detachment. Finally, CK-3 molecules exhibited stable adsorption on rock walls, influencing wetting reversal. Zeta potential measurements exceeding 30 mV indicated stability. In aged capillary tubes, a 0.3 wt% CK-3 solution exhibited a rise height of 2.9 cm. Imbibition experiments on natural core samples showed a water imbibition efficiency of 8.73 %, compared to a significantly improved efficiency of 50.78 % with a 0.3 wt% CK-3 solution. This study also demonstrated the imbibition process and mechanisms of the CK-3, providing novel insights for the efficient development of unconventional oil reservoirs and the enhancement of crude oil recovery rates.

Preparation of novel polymeric surfactants based on synergistic effects and analysis of the mechanism driving the oil-displacement process and enhanced oil recovery

Polymeric surfactants have been favored by researchers due to their ability to increase the viscosity of the aqueous phase, reduce the viscosity of the oil phase, and avoid the chromatographic separation effects of polymer-surfactant binary combination flooding. However, there is little research into the oil-displacement effect of polymer surfactants, and the mechanism whereby it enhances heavy oil recovery remains unclear. To fill this theoretical gap in the research into the oil-displacement mechanism of polymer surfactants, a novel polymeric surfactant PNBM was prepared using acrylamide, acrylic acid, nonylphenol ethoxylate (NP), and 4-vinylbiphenyl (VB). The chemical structure of PNBM was validated by characterization methods such as 1HNMR, FT-IR spectroscopy and elemental analysis. The mechanism of PNBM for enhancing heavy oil recovery was systematically studied based on the displacement and profile control by thickening, reducing viscosity by emulsification, and peeling of oil films and droplets. Polymeric surfactant PNM containing NP and polymeric surfactant PBM containing VB were used as control groups. Benefiting from the synergistic effect of two viscosity-reducing monomers, PNBM has better oil displacement effect compared to PNM and PBM: (1) a tighter adsorption film can be formed at the water–oil interface due to the good interfacial activity of PNBM, so that the average viscosity reduction rate of PNBM at a low concentration reaches 85.5 %; (2) PNBM can significantly increase the viscosity of aqueous solutions (increasing to 38.2 mPa·s), decrease the water–oil mobility ratio, and expand the swept volume; (3) PNBM can reduce the contact angle of the water phase on the oil-wet surface to 62.8°, supplemented by its good viscoelasticity, thereby improving the oil-washing efficiency. Therefore, under the triple effects of displacement and profile control by thickening, reducing viscosity by emulsification, and peeling of oil films and droplets, PNBM can enhance heavy oil recovery by 17.7 %, significantly improving the beneficial industrial exploitation of heavy oil reservoirs.

Composition and Injection Rate Co-Optimization Method of Supercritical Multicomponent Thermal Fluid Used for Offshore Heavy Oil Thermal Recovery

Supercritical multicomponent thermal fluid injection is a new technology with great potential for offshore heavy oil thermal recovery. In the process of thermal fluid generation, the reaction conditions including temperature, pressure, and the organic mass concentration in the reaction material will significantly affect its composition and injection rate and will further affect the thermal recovery and development quality of heavy oil. However, there is a lack of relevant research on the variation rules and control methods of the composition and injection rate of supercritical multicomponent thermal fluids, resulting in a lack of technical mechanisms for effective optimization. To fill this gap, a reaction molecular dynamics simulation method was used to simulate thermal fluid generation under different temperatures, pressures, and organic mass concentrations. The changes in thermal fluid composition and yield with reaction conditions were studied, and a control model of thermal fluid composition and yield was established. The proportional relationship between the thermal fluid generation scale of an offshore heavy oil platform and the simulated thermal fluid generation scale is analyzed, and a collaborative optimization method of thermal fluid composition and injection rate in field applications is proposed. The results show the following: (1) The higher the mass concentration of organic matter, the higher the content of supercritical carbon dioxide and supercritical nitrogen in thermal fluids, and the lower the content of supercritical water. (2) The higher the temperature and pressure, the higher the thermal fluid yield, and the higher the organic mass concentration, the lower the thermal fluid yield. (3) The component fitting model conforms to the power function relationship, and the coefficient of determination R2 is greater than 0.9; the yield fitting model conforms to the modified inverse linear logarithmic function relationship, the determination coefficient R2 is greater than 0.8, and the fitting degree is high. (4) The ratio between the actual injection rate of thermal fluids in the mine field and the molecular simulated thermal fluid yield is the ratio of organic matter mass in the platform thermal fluid generator and organic matter mass in the simulated box. (5) Based on the composition and yield control model, combined with the simulation of the ratio relationship between yield and injection rate in the field, a collaborative optimization method of thermal fluid composition and injection rate was established. The research results can provide an effective technical method for predicting, controlling, and optimizing the composition and injection rate of supercritical multicomponent thermal fluids.

Experimental evaluation of acid number effect on interfacial tension between nitrogen and mixtures of petroleum fractions including diesel fuel and gasoline at different pressures

Crude oil is made up of very complex compounds, which are found in polar organic substances especially organic acid compounds in the majority. Although organic acid content in crude oil is low, the presence of organic acids affects the interfacial tension (IFT) in oil reservoirs thereby altering the enhancement of oil recovery using nitrogen gas (N2) injection. Therefore, in this study, the effects of pressure (1 to 35 bar), the percentage of aromatic compounds (0.0 to 100 vol%) in the aliphatic hydrocarbon samples and the organic acid (benzoic acid) content (0.0 to 0.8 g.L− 1) on IFT between a mixture of gasoline/diesel fuel and N2 were investigated at a temperature of 298 K. IFT does not necessarily decrease as pressure increases for the sake of existence of aromatic compounds. IFT alteration for gasoline was more (about 8 dyne.cm− 1) than for diesel fuel (approximately 4 dyne.cm− 1) during pressure increased from 1 to 35 bar due to the replacement of heavy long chain aliphatic compounds instead of light aromatic matters. The effect of IFT alteration between N2 and diesel fuel during increasing the organic acid content was little (approximately 1.5 dyne.cm− 1), in contrast, this effect was more noticeable for N2/gasoline (about 8 dyne.cm− 1). In addition, a reduced cubic model for estimating IFT between N2 and petroleum fractions in terms of pressure, petroleum fraction composition and organic acid content was proposed with an average relative error of less than 2.6%.

Improving In Situ Combustion for Heavy Oil Recovery: Thermal Behavior and Reaction Kinetics of Mn(acac)3 and Mn-TO Catalysts

In this research work, the catalytic performances of two manganese-based catalysts, manganese (III) acetylacetonate (Mn(acac)3) and manganese tallate (Mn-TO), were studied during the process of Ashalcha heavy oil oxidation under in situ combustion conditions. DSC analysis shows distinct thermal behavior of both ligated catalysts during low- and high-temperature oxidation phases (LTO and HTO); for example, the shifting in peak temperature (Tp) in the HTO at a heating rate of 10 °C/min was reduced by approximately 5.3% for Mn-TO and 2.24% for Mn(acac)3 when compared with uncatalyzed heavy oil. Combined isothermal kinetic analyses using the Friedman and Kissinger–Akahira–Sunose analytic methods have provided insights about activation energies and frequency factors over the whole conversion range, where the catalytic performance of Mn-TO showed low activation energies in both LTO and HTO (Eα of Mn-TO was approximately 13.33% (LTO) and 7.68% (HTO) less than with the heavy oil alone). In addition, calculations of the effective rate constant confirmed the increased oxidation rate trend of both catalysts, with Mn-TO exhibiting the highest values. The findings highlight the potential of these manganese-based catalysts, the Mn-TO catalyst in particular, in optimizing heavy oil oxidation processes. The overall results further contribute to developing more efficient ligand catalyst complexes for sustainable heavy oil recovery while continuously improving their efficient application during in situ combustion in the petroleum industry.

Dynamics of microbial-induced oil degradation at the microscale.

Microbial-induced oil degradation (MIOD) has a wide range of applications, such as microbial enhanced oil recovery and bioremediation of oil pollution. However, our understanding of MIOD is still far from complete. Particularly, how is the dynamics of degradation process at the microscale level with a single-cell resolution remains to be disclosed. In this work, using hexadecane droplets in water as a model system, we have studied the dynamics of hexadecane degradation by different strains, including Pseudomonas aeruginosa PAO1, IMP68, O-2-2, and Dietzia sp. DQ12-45-1b, at the microscale. Based on visualization of MIOD, the dynamics of MIOD can be characterized by a three-stage process, including adhesion, adaptation, and degradation stages. Although different strains showed similar three-stage dynamics of MIOD, the effective degradation rate varied and followed an order of PAO1 > O-2-2 > IMP68 > DQ12-45-1b under aerobic conditions. Different oxygen conditions were also tested, and the dynamics of MIOD was slowed down under anaerobic conditions in comparison to under aerobic conditions. Further investigations at the degradation stage revealed that biofilms formed at the oil-water interface enhanced oil degradation, but a prerequisite for such enhanced degradation is proper stimulation of biofilm cells in the course of biofilm formation. The findings in this work provided a detailed picture on the dynamics of MIOD at the microscale and would be beneficial for better applications of MIOD.IMPORTANCEMicrobial-induced oil degradation is environmental friendly and economic and has become a promising technique in the fields of enhanced oil recovery and remediation of crude oil-polluted environments. For better applications of microbial-induced oil degradation, understanding the degradation dynamics particularly at the microscale is crucial. In this study, we investigated the degradation dynamics of hexadecane oil droplets incubated with different strains, including Pseudomonas aeruginosa PAO1, O-2-2, IMP68, and Dietzia sp. DQ12-45-1b at the microscale by employing microdroplet-based methods and bacterial tracking techniques. The findings in this study provided a detailed picture on the dynamics of microbial-induced oil degradation at the microscale, which will deepen our understandings on the biodegradation mechanisms of alkanes and shed insights for developing more effective biodegradation techniques.