Heavy Oil Recovery Research Articles

Silica aerogel nanoparticle-stabilized flue gas foams for simultaneous CO2 sequestration and enhanced heavy oil recovery

With declining conventional reserves, tapping heavy oils generates substantial emissions yet is essential to meet energy demands. This study pioneers an integrated approach using silica aerogels to develop thermally stable flue gas foams for enhanced CO2 sequestration and heavy oil recovery. Microfluidic experiments and molecular dynamics simulations revealed a 5-fold decrease in gas diffusion rates for aerogel-stabilized versus pure surfactant foams at 95 °C due to the ultralow thermal conductivity of the nanoparticle coating layer. The thermally stable nanoengineered foams demonstrated a remarkable 81.23% CO2 trapping efficiency in heterogeneous cores, surpassing conventional flue gas foam. Additionally, three-dimensional simulations in an oil reservoir model showed improved vertical conformance and oil recovery with aerogel-stabilized foam. The exceptional insulating properties redirected heat downward to enhance sweep efficiency. This novel concept transforms flue gas emissions into value-added foams for concurrent environmental and productivity benefits during heavy oil development.

Kinetics of thermal decomposition of crude oils: Insights from principal component analysis and products characterization

Energy demand is souring, and fossil fuel reserves are dwindling, making heavy oil resources more attractive. In this study, thermogravimetric and Py-GC/MS analyses were conducted on Iranian crude oil samples to compare high and low API (American Petroleum Institute) crude oils. A kinetic study based on mass loss of crude oil was performed using three model-free methods and distributed activation energy model (DAEM). To do that, TG analysis carried out, the temperature was increased from room temperature to 1000 °C with heating rates of 10, 20, and 30 °C min−1. Activation energy (Ea) and pre-exponential factor (A0) were estimated from Friedman, Kissinger–Akahira–Sunose (KAS), and Ozawa-Flynn–Wall (OFW) methods for oil sample. The Ea and A0 for heavy crude oil (Koroosh) pyrolysis varied between 59.85 and 193.83 kJ mol−1 and 1.34 × 105 to 4.36 × 1011 s−1, respectively. For light crude oil sample Lavan, the Ea and A0 ranged between 35.93 to 62.89 kJ mol−1 and 337.41–722.65 s−1, respectively. Pearson's correlation analysis found that the activation energy barrier increases as the reaction progresses and the temperature rises. This makes it harder to form the activated complex, which is a key step in the reaction. Principal component analysis supported these findings. Saturated and aromatic hydrocarbons were liberated at mild temperature while the resins and asphaltenes consecutively released in favorable condition for developing sustainable heavy oil recovery systems. Py/GC–MS analysis shows the evolution of saturated hydrocarbon in Koroosh-oil and aromatic hydrocarbons in Lavan-oil and demonstrates their suitability for fuel applications.

Preparation and Performance Evaluation of Amphiphilic Polymers for Enhanced Heavy Oil Recovery.

The continuous growth in global energy and chemical raw material demand has drawn significant attention to the development of heavy oil resources. A primary challenge in heavy oil extraction lies in reducing crude oil viscosity. Alkali-surfactant-polymer (ASP) flooding technology has emerged as an effective method for enhancing heavy oil recovery. However, the chromatographic separation of chemical agents presents a formidable obstacle in heavy oil extraction. To address this challenge, we utilized a free radical polymerization method, employing acrylamide, 2-acrylamido-2-methylpropane sulfonic acid, lauryl acrylate, and benzyl acrylate as raw materials. This approach led to the synthesis of a multifunctional amphiphilic polymer known as PAALB, which we applied to the extraction of heavy oil. The structure of PAALB was meticulously characterized using techniques such as infrared spectroscopy and Nuclear Magnetic Resonance Spectroscopy. To assess the effectiveness of PAALB in reducing heavy oil viscosity and enhancing oil recovery, we conducted a series of tests, including contact angle measurements, interfacial tension assessments, self-emulsification experiments, critical association concentration tests, and sand-packed tube flooding experiments. The research findings indicate that PAALB can reduce oil-water displacement, reduce heavy oil viscosity, and improve swept volume upon injection into the formation. A solution of 5000 mg/L PAALB reduced the contact angle of water droplets on the core surface from 106.55° to 34.95°, shifting the core surface from oil-wet to water-wet, thereby enabling oil-water displacement. Moreover, A solution of 10,000 mg/L PAALB reduced the oil-water interfacial tension to 3.32 × 10-4 mN/m, reaching an ultra-low interfacial tension level, thereby inducing spontaneous emulsification of heavy oil within the formation. Under the condition of an oil-water ratio of 7:3, a solution of 10,000 mg/L PAALB can reduce the viscosity of heavy oil from 14,315 mPa·s to 201 mPa·s via the glass bottle inversion method, with a viscosity reduction rate of 98.60%. In sand-packed tube flooding experiments, under the injection volume of 1.5 PV, PAALB increased the recovery rate by 25.63% compared to traditional hydrolyzed polyacrylamide (HPAM) polymer. The insights derived from this research on amphiphilic polymers hold significant reference value for the development and optimization of chemical flooding strategies aimed at enhancing heavy oil recovery.

Hybrid low salinity water and surfactant process for enhancing heavy oil recovery

Combining low salinity water (LSW) with surfactants has an enormous potential for enhancing oil recovery processes. However, there is no consensus about the mechanisms involved, in addition to the fact that several studies have been conducted in model systems, while experiments with rocks and reservoir fluids are scarce. This study presents a core-flooding experiment of LSW injection, with and without surfactant, using the core and heavy oil samples obtained from a sandstone reservoir in southeastern Mexico. The effluents and the crude oil obtained at each stage were analyzed. The study was complemented by tomographic analysis. The results revealed that LSW injection and hybrid process with surfactants obtained an increase of 11.4 percentage points in recovery factor. Various phenomena were caused by LSW flooding, such as changes in wettability and pH, ion exchange, mineral dissolution, detachment of fines and modification of the hydrocarbon profile. In the surfactant flooding, the reduction of interfacial tension and alteration of wettability were the main mechanisms involved. The findings of this work also showed that the conditions believed to be necessary for enhanced oil recovery with LSW, such as the presence of kaolinite or high acid number oil, are not relevant.

Reservoir Simulation of Cross CAGD (XCAGD) Thermal Enhanced Heavy Oil Recovery using Foam with Steam Injection

Among the most important thermal oil recovery enhancement methods, it is possible to point out In-Situ Combustion (ISC) and Steam Assisted Gravity Drainage (SAGD) processes. The “Combustion Assisted Gravity Drainage (CAGD) process” as an oil recovery enhancement method is a specific combination of two methods: 1-In-Situ Combustion process mostly in terms of the process mechanism and the combustion reactions and also the injected gas type. and 2-Steam Assisted Gravity Drainage process mostly in terms of well configuration. Cross CAGD (XCAGD) is akin to CAGD except that the horizontal injectors are placed perpendicular to the horizontal production wells. By combining both gravity drainage and lateral displacement, XCAGD is able to hasten recovery, diminish steam requirements and promote economic potential compared to CAGD. XCAGD is better suited for several near producers with several perpendicular injectors to achieve a better development. It should be noted that near above kick off point of the vertical injectors with the horizontal producers in XCAGD, slotted liner embedding is pivotal. In this paper, a reservoir simulation of Cross CAGD (XCAGD) thermal enhanced heavy oil recovery using Foam with Steam injection has been precisely scrutinized and studied then some good results have been obtained. These good results encompass more recovery factor of produced oil about %3-5 derived from FOIP curves.

A review of ionic liquids: Recent synthetic advances and oilfield applications

BackgroundIonic liquids have received a lot of interest in recent years from scientists and academics due to their distinctive qualities, including low vapor pressure, low toxicity, high thermal stability, and recyclability. Ionic liquids have become a more sustainable substitute for volatile organic solvents. MethodsIonic liquids can be synthesized with tailored properties by combining specific cationic and anionic components. Because of their distinct physiochemical characteristics and advantages, ionic liquids were used in different industrial processes such as organic/inorganic synthesis, biomass conversion, desulfurization, catalysis, electrochemistry, spectroscopy, and energy storage. FindingsThe primary goal of the current review is to outline the numerous synthetic routes for various classes of ionic liquids such as imidazolium, phosphonium, sulfonium, pyridinium, ammonium, pyrazolium, triazolium, and protic ionic liquids. Ionic liquids have drawn interest for a variety of oilfield applications because of their stability under challenging reservoir conditions, tunability, and low toxicity. This review primarily concentrates on the numerous oilfield applications including demulsification, drilling, heavy oil recovery, and CO2 capture. This review also covers the challenges and drawbacks associated with the synthesis and applications of ionic liquids and provides a reasonable solution and potential ideas to address the challenges.

Bacterial Cultural Media Containing Lipopeptides for Heavy Oil Recovery Enhancement: The Results of Sand-Packed Column Experiment

Currently, microbial enhanced oil recovery (MEOR) is of great interest because of its potential high efficiency and low environmental impact. Biosurfactants, in the purified form or contained in the bacterial cultural media, are one of the promising directions in MEOR because they are more stable in response to different environmental factors than life microorganisms are. However, the extraction and purification of biosurfactants, as well as their working concentrations and efficacy in real oilfield conditions remain a challenge. In the present work, cultural media of two novel bacterial isolates (Bacillus pumilus and Peribacillus simplex) were used in a model experiment with sand pack columns to enhance the recovery of heavy oil from Romashkino oilfield (Russia). Using FTIR and TLC methods, it was demonstrated that both cultural media contained lipopeptides. In the genome of both bacterial isolates, genes srfAA, fenD and bamC encoding synthesis of surfactin, fengycin, and bacillomycin, respectively, were revealed. The oil recovery efficacy of cell-free cultural media after 24 h of cultivation was 34% higher and 16% lower as compared with synthetic surfactant for B. pumilus and P. simplex, respectively. It can be concluded that the high-cost step of biosurfactants separation and purification may be excluded, and cell free cultural media of the isolates may be directly used in field conditions to enhance the recovery of heavy oils.

Performance evaluation of a novel multi-metal catalyst solution obtained from electronic waste bioleaching on upgrading and enhancing oil recovery

Due to the high costs and associated high CO2 emissions of thermal methods, this study focuses on upgrading heavy oil and enhancing oil recovery within reservoir temperature ranges. In this research, a novel, low-cost, and environmentally friendly multi-metal catalyst has been used, which is actually extracted from electronic waste (E-waste). At optimal conditions, which include 80 °C, 12 h of retention time, and 0.2 % v/v of the multi-metal catalyst, this catalyst effectively reduced the viscosity of heavy oil from 687 to 580 mPa.s. To analyze heavy oil before and after the process, Fourier transform infrared spectroscopy (FTIR) was conducted. FTIR spectra indicates that the multi-metal catalyst has reduced the amount of aromatic compounds, shortened hydrocarbon chains, and decreased double and triple bonds. Micromodel tests were conducted by multi-metal catalyst flooding at optimal temperature and retention time obtained from static experiments. Heavy oil recovery through multi-metal catalyst flooding reached 38 %, which is a 10.5 % increase compared to deionized water flooding. The contact angle of the rock was measured after contact with the multi-metal catalyst. The multi-metal catalyst reduced the contact angle by 55 °, changing the wettability of carbonate rock from oil-wet to water-wet. The absorption test indicates that the multi-metal catalyst dissolves certain metals in the rock, most likely due to the high pH of the catalyst. As a result, the permeability of the rock may increase due to the dissolution of the rock metals.

Optimization of injection parameters of a microemulsion-type oil displacement agent for heavy oil recovery

The conventional viscosity reduction technology through commercial oil-soluble agents for enhanced oil recovery in heavy oil reservoirs has potential safety hazards. In this work, micro-emulsification of heavy oil is proposed as a means of reducing its viscosity for ease of its recovery. The microemulsion-type oil displacement agent was developed, and its performance was characterized by its pseudoternary phase diagram and dynamic light scattering tests. The core tests were used to study the effects of injection volume, injection speed, and subsequent water flooding speed on the oil recovery factors. These results were used to determine the optimal injection parameters. Furthermore, the displacement mechanism for heavy oil was determined based on combined macroscopic and microscopic visual tests. The results showed that the optimal injection volume is 0.15 PV (pore volume), the injection rate is 0.10 ml/min, and the subsequent water flooding rate is 0.20 ml/min. Based on the optimal parameters, the oil recovery efficiency can reach up to 39.83%, which is 25.69% higher than water flooding process. The displacement mechanism of the microemulsion can be divided into three stages. First, when the microemulsion is in contact with the heavy oil, the solubilization occurs spontaneously, and the heavy oil is peeled off from the rock surface. Then, the solvent in the microemulsion interacts with the heavy oil to achieve the viscosity decrease in the heavy oil. Third, during the water flooding process, the viscosity-reduced heavy oil can be emulsified to form oil-in-water emulsion, further realizing the viscosity reduction of heavy oil.

Adaptability to Enhance Heavy Oil Recovery by Combination and Foam Systems with Fine-Emulsification Properties

Emulsification is increasingly emphasized for heavy oil recovery through chemical flooding. However, whether systems with fine-emulsification (FE) properties significantly outperform conventional ultra-low interfacial tension (IFT) systems, especially under varying water-oil viscosity ratios, remains unclear. In this research, two FE systems and one conventional ultra-low IFT system are compared in terms of their IFTs, emulsification properties, foaming behaviors, and heavy oil recovery (in the form of combination flooding and foam flooding). The results show that FE systems 1# and 2# can generate more stable emulsions of heavy oil than the traditional ultra-low IFT variant 3#. During the first combination flooding, FE systems recover 24.5% and 27.9% of the oil after water, obviously surpassing 21.0% of the ultra-low IFT system 3#; but as this ratio increases to 0.45, those factors become very similar to ones of 33.2%, 34.5% and 32.9%, with the former no longer outperforming the latter. In the second trials of foam flooding, at a lower water-oil viscosity ratio of 0.05, FE foam 1# becomes less effective than the ultra-low IFT 3#, with oil recovery factors of 27.2% and 31.6%, respectively; but foam 2# (combining medium emulsification and ultra-low IFT) remains optimal, with the highest recovery factor of 40.0%. Again, as this ratio becomes 0.45, the advantages of FE systems over the ultra-low IFT system are almost negligible, generating similar oil recoveries of 39.2%, 41.0% and 39.4%.

Stability Analysis of Anionic-CO2-Soluble Surfactant Di-(2-ethylhexyl) Sodium Sulfosuccinate-Assisted Oily Foam Based on Statistical Analysis of Bubble Dynamic Characteristics.

Currently, oily foam stability in CO2 injection for heavy oil recovery exhibits inadequacies that considerably constrain its extensive application. Some scholars have conducted research demonstrating that CO2-soluble surfactants can assist in inducing heavy oil to form oil-based foams (oily foam). In this study, stability tests for the oily foam were conducted at different surfactant concentrations using a visualized PVT cell. Oily foam stability was assessed by calculating the comprehensive foam index (S) and analyzing the bubble images. The research indicates that AOT can effectively reduce the interfacial tension between oil and gas. At a concentration of 0.1 wt % AOT, the interfacial tension can be effectively reduced from 1.75 to 1.14 mN/m. The concentration of 0.3 wt % AOT represents a turning point, with an S of 16 101.7 mL·min. Beyond this concentration, the increase in S becomes less pronounced. As the concentration of CO2-soluble surfactant is increased from 0.1 to 0.5 wt %, the average bubble radius decreases from 2.74 to 0.43 mm, while the number of bubbles per unit area increases from 5.56 to 81.1 per cm2. With an increasing concentration of the CO2-soluble surfactant, the system generates more and smaller gas bubbles within the oily foam, resulting in a slower bubble coalescence. The findings of this study are poised to play a pivotal role in enhancing heavy oil recovery efficiency.

Heavy oil separation and recovery by the self-assembly of polymers and silica particles in hypersaline water

Emulsification and separation are of great significance in oil recovery. Herein, we report a synergic system of polymers and silica particles, which can achieve the emulsification and separation of heavy oil through the alkaline/acidic solution. Since the high salinity of formation water is an inevitable issue for chemical waterflooding, the effects of salinity on the properties of heavy oil emulsions were investigated by the zeta potential, interfacial tension (IFT), separation efficiency, dynamic light scattering (DLS), and rheology in experiments. The results show that heavy oil emulsions at extreme salinity (up to 50 g/L) remain stable under alkaline conditions. But conversely, the separation process of heavy oil emulsions is expedited under acidic conditions. Furthermore, the interaction mechanism is also elucidated by molecular dynamics simulations to provide a well-researched interpretation of the experimental phenomena. The self-assembly between the polymer and silica particles is seriously affected by the salt ions through the electrostatic screening effect, with increasing zeta potential values from −52.5 mV to −18.1 mV, and the interfacial films are crippled, exhibiting more viscous properties, which induces the separation of heavy oil emulsions. However, it can be stable under alkaline conditions with separation efficiencies of less than 14.3% in 24 h. This novel reversible PS system is used in hypersalinity (30 g/L) to realize emulsification and separation without any demulsifiers, breaking through the current salinity limit of polymer waterflooding (EOR increased by 15.51%). The findings of this study can help for a better understanding of the molecular mechanism of switchable heavy oil emulsions and develop a potential solution for EOR in reservoirs with high salinity.

Foam Systems for Enhancing Heavy Oil Recovery by Double Improving Mobility Ratio

The recovery of heavy oil is challenging due to its high viscosity. Especially in water flooding, the high viscosity of heavy oil induces a high water/oil mobility ratio, resulting in frequent channeling and fingering. In the present work, the viscosity reduction in heavy oil caused by foaming agents is studied. Among the studied foam systems, the KX-048 foaming agent had the best oil viscosity reduction performance. It also shows excellent foaming performance, including large foam volume, long foam half-life, and high foam comprehensive index. With the reduction in oil viscosity, the KX-048 foaming agent decreases the foam/oil mobility to 0.28, which is beneficial for controlling gas channeling and fingering in foam flooding. Moreover, Foam flooding experiments in heterogeneous sand-pack models indicate that KX-048 has excellent efficiency in improving oil recovery, especially in the low-permeable tube. The chosen KX-048 foaming agent could provide a promising pathway for improving heavy oil recovery.

Properties and Aggregation Behavior of Gemini Surfactants for Heavy Oil Recovery in High Temperature and Salinity Conditions

Properties and Aggregation Behavior of Gemini Surfactants for Heavy Oil Recovery in High Temperature and Salinity Conditions

A novel active amphiphilic polymer for enhancing heavy oil recovery: Synthesis, characterization and mechanism

Amphiphilic polymers represent significant ability in emulsifying crude oil during the displacement, enabling effective control the oil/water interface mobility and reduction of heavy oil viscosity. Herein, an amphiphilic polymer, named PMC16, was copolymerization using by hydrophobic monomer C16DMAAC, along with acrylamide and acrylic acid as comonomers. The structure of PMC16 was identified by 1H NMR, and FT-IR. The potential of PMC16 for oil recovery enhancement was evaluated through assessments of fluid viscoelasticity, reduction in oil viscosity, wettability alternation and interfacial activity between heavy oil and PMC16. The results reveal that PMC16 showed well shear resistance due to the hydrophobic association between its molecular chains. In addition, the PMC16 can effectively decrease the viscosity of the oil phase through emulsification. The viscosity reduction achieved by PMC16 for heavy oil surpasses 95% under the condition of 60 °C, oil–water ratio of 3:7 and a concentration of 3000 mg/L. Additionally, PMC16 solution induces a shift in the wettability of solid surfaces towards water-wet characteristics, with the oil droplet contact angle reducing from 125° to 54°. Such wettability transformation proves advantageous for spontaneous imbibition, especially when considering capillary force as the driving mechanism. Furthermore, the results of oil displacement performance experiments substantiated that PMC16 contributed to a 17.9% increase in the recovery rate of heavy oil. The utilization of PMC16 holds significant theoretical importance in augmenting the recovery of heavy oil.

Experimental investigation on supercritical multi-thermal fluid flooding using a novel 2-dimensional model

Supercritical multi-thermal fluid (SCMTF) is a promising alternative to traditional thermal agents for deep heavy oil recovery. However, no 2-dimensional experimental investigation on SCMTF flooding has been conducted due to the limitations of existing apparatuses. Therefore, the primary objective of this study is to develop a novel assembly for investigating the performance of SCMTF flooding. Subsequently, the SCMTF chamber evolution is characterized using newly developed equipment, and enhanced oil recovery (EOR) mechanisms are proposed. Finally, the effects of the injection temperature, injection pressure, scN2/scCO2 mixture, and heavy oil viscosity on SCMTF are comprehensively studied. The results show that the SCMTF chamber displays an inverted trapezoidal shape with a uniform front. SCMTF flooding can enhance heavy oil recovery by 13.36% relative to steam flooding by sweep area expansion, oil mobility improvement, and miscible flooding. Increasing the injection temperature, injection pressure or scN2/scCO2 mixture to SCW molar ratio can facilitate the production of heavy oil, while using SCMTF in an extra-heavy oil cannot maximize the EOR effect of SCMTF. Notably, the high yield of coke produced at elevated temperatures may lead to potential formation damage.

IMPROVEMENT OF FUEL OIL VACUUM RECTIFICATION PROCESS

Primary oil distillation units form the basis of all oil refineries; the quality and yield of the resulting fuel components, as well as raw materials for secondary and other oil refining processes, depend on their operation. Many Atmospheric Vacuum Tubing (AVT) plants are characterized by low recovery of heavy vacuum gas oil. Insufficient selection of heavy vacuum gas oil production leads to a high yield of vacuum residue - tar, which reduces the volume of oil refining in general.The article analyzes ways to improve the process of vacuum distillation of fuel oil at CDU/AVT primary oil distillation units, and searches for ways to increase the efficiency of already built CDU/AVT plants by increasing the selection of heavy vacuum gas oil. Options for technical re-equipment are presented to improve the technical and economic efficiency of atmospheric-vacuum tubing plants with the maximum use of the best achievements in this area and the maximum possible selection of heavy vacuum gas oil at existing primary oil distillation units. The schemes of intensification during vacuum distillation by the method of fractionation of hydrocarbon raw materials by exposing it to electromagnetic oscillations, by the method of gas oil cryolysis. Besides, the schemes of fuel oil distillation according to a two-column scheme and the rectification of half-tar in an additional vacuum column are considered. The main features in the technological design of the process, as well as the features of installation operation, are noted. The proposed schemes make it possible to obtain high-quality feedstock for catalytic cracking and hydrocracking with a high recovery of vacuum gas oil.

Reducing CO2 emissions and improving oil recovery through silica aerogel for heavy oil thermal production

Heavy oil reserves comprise more than 60% of global crude oil resources, and thermal oil recovery techniques, especially steam injection, are widely utilized for extracting heavy oil. However, these thermal production processes are characterized by high energy consumption and carbon emissions, which pose significant challenges in reducing CO2 emissions. In response to these challenges, this study presents a novel approach that combines silica aerogel with CO2-assisted thermal recovery technology. Our findings demonstrate that the incorporation of aerogel nanoparticles enhances the adsorption capacity of CO2 in the aqueous phase. The adsorption behavior of CO2 in silica aerogel aligns with the Langmuir model. When silica aerogel nanoparticles are employed in steam flooding, a notable improvement is observed in both oil recovery and CO2 sequestration rate. Molecular dynamics simulations reveal that the porous structure of aerogel enables the adsorption of light saturates molecules from crude oil, promoting their diffusion into the aqueous phase and ultimately enhancing oil recovery. The steam condensation experiments clearly demonstrate that the presence of aerogel and CO2 exerts a substantial influence on the condensation heat transfer of steam, resulting in a reduction in the condensation heat transfer rate between the steam and the cooling wall. Additionally, molecular dynamics simulations reveal that silica aerogel nanoparticles exhibit an affinity for adsorbing onto hydrophobic quartz surfaces, forming an insulating layer between steam and quartz, thereby facilitating CO2 sequestration. The introduction of silica aerogel nanoparticles expands the swept volume of steam heat. This study provides valuable insights into the underlying mechanisms responsible for improved CO2 sequestration and increased oil recovery through the implementation of silica aerogel nanoparticles, offering fresh perspectives on heavy oil recovery.

Investigation into main controlling factors and prediction model of L245NS steel corrosion rate in CO2–O2–SO2–H2S–H2O environment

Multi-component thermal fluid flooding is an increasingly mature technology for heavy oil recovery. However, the production of associated gas containing highly corrosive CO2/O2/SO2/H2S/H2O impurities can lead to corrosion and perforation failure in gathering pipelines. This study systematically investigated the effects of temperature/CO2/O2/SO2/H2S on L245NS steel corrosion in a CO2–O2–SO2–H2S–H2O environment and analyzed the correlation between these factors and corrosion rate. The corrosion behavior of L245NS steel in a CO2–O2–SO2–H2S–H2O environment was investigated through weight-loss experiments and surface characterization techniques. An empirical model for predicting the corrosion rate in this environment was established based on the obtained results. The results indicated that the sequence of importance for corrosion rate was as follows: O2 (0.8181) > H2S (0.7511) > Temperature (0.7491) > CO2 (0.7312) > SO2 (0.7017). Surface characterization revealed that the predominant corrosion products were FeCO3, FeS2, FeS, Fe(OH)3, FeOOH, Fe3O4, Fe2O3, elemental sulfur and FeSO4·4H2O. The corrosion reaction involved CO2/O2/SO2/H2S while synergistic reactions between SO2–O2 and SO2–H2S further promoted corrosion. Finally, an empirical model for the corrosion rate of L245NS steel in a CO2–O2–SO2–H2S–H2O environment was established. The fitting error ranged from 0.03% to 8.99%, and the verification error ranged from 2.62% to 14.83%. This model can provide a valuable reference for preventing and controlling pipeline corrosion.

Characteristics and Stabilization Mechanism of Three-Phase Foam: Improving Heavy Oil Recovery via Steam Stimulation through Two-Dimensional Visual Model

There is a problem of a rapid decline in production caused by the repeated heating of the near-wellbore zone during steam stimulation. Finding a suitable foam system to expand the area of the steam chamber and slow down the rapid production of hot water during the recovery process can effectively improve the effect of steam stimulation. In this paper, CGS foam was prepared with high-temperature-resistant surfactant GD, graphite particles, and clay particles. Through the study of foam properties, it was found that with the addition of particles, the strength of the foam’s liquid film, half-life time, and temperature resistance was greatly improved. The appropriate permeability of the CGS foam and the movement characteristics of it in formations with different permeabilities were studied through a plugging experiment with a sand pack. The plugging performances of the GD foam, CGS foam, and pure particles in a simulated reservoir were compared. The development of the steam cavity during the steam stimulation process and the influence of injecting GD foam and CGS foam on the flow in the simulated reservoir were studied through a two-dimensional visualization model. The temperature resistance and stability of the CGS foam were better than those of GD foam in the simulated formation.