The development of deep/ultra-deep heavy oil and underground hydrogen production have led to the increasing significance of oilfield chemical igniters as a crucial trigger technique. Therefore, this paper sorts out the development process of chemical ignition technology in oilfields, focusing on a detailed summary of ignition methods with potential in deep/ultra-deep reservoirs. The chemical ignition method is particularly prominent because it is not limited by depth. The chemical igniter types, mechanism, mathematical models, and field applications of chemical ignition methods have been organized, pointing out the current shortcomings. The current chemical ignition agents are mainly granular ignition agents, which have not considered the evaluation of ignition performance under high pressure, and the synergistic effect between ignition agents and crude oil has not been taken into account. In addition, the effect of ignitor flow on heat diffusion is still not considered in the mathematical model. Thickened self-igniting fluid chemical ignition agent and low-flammability and high calorific value solid particle ignition agent will be the main development direction of chemical ignition agent construction. The results further point to the future research direction of chemical ignition methods, which will accelerate the development process of deep/ultra-deep reservoirs.

Supercritical carbon dioxide (ScCO2) fracturing fluids have been limited in their application in unconventional reservoirs due to their weak proppant-carrying capacity resulting from their low viscosity. Consequently, numerous scholars have focused on modifying siloxanes to enhance their solubility and thickening performance in ScCO2. In this paper, the cohesive energy density, interaction energy, radial distribution function, shear viscosity and electrostatic potential distribution of modified siloxane with ScCO2 were calculated using molecular dynamics simulation. The effects of different temperatures and pressures on the dissolution and thickening ability of modified siloxanes in ScCO2 were investigated.The simulation results indicate that high temperature and low pressure have limited effects on promoting the solubility of modified siloxanes in ScCO2, with temperature exerting a more significant influence on solubility behavior than pressure. Additionally, PD4H+TMPTMA is less soluble in ScCO2 compared to PD4H+TAIC. The binding energy of ScCO2 and modified siloxanes decreases with increasing temperature but increases with increasing pressure. Van der Waals interactions and electrostatic interactions play decisive roles in the solubility of modified siloxanes in ScCO2. Finally, the thickening mechanism of modified siloxanes in ScCO2 was elucidated based on molecular structure and binding energy interactions.In summary, this paper aims to provide options and assistance in synthesis of better ScCO2 thickeners for unconventional reservoir fracturing applications through the study of modified siloxanes.

Nowadays, high-phase-inversion in situ emulsification technology has shown great potential in enhancing oil recovery from high-water-cut thin-oil reservoirs. However, emulsification characteristics, interfacial properties, and the mechanism of high phase inversion have not been systematically described. In this study, an emulsification experiment was conducted to investigate the effects of shear time, shear rate, and temperature on the phase inversion of thin oil. Furthermore, the influence of resin and wax on the dispersion of asphaltene was studied through microscopic morphology analysis. Interfacial tension measurement and interfacial viscoelasticity analysis were carried out to determine the interaction characteristics of asphaltene, resin, and wax at the interface. The results showed that, at 50 °C, the phase-inversion point of thin oil reached as high as 75%, and even at 60 °C, it remained at 70%. The shear time and shear rate did not affect the phase-inversion point of thin oil, while an increase in temperature led to a decrease in the phase-inversion point. Moreover, compared to the 20% phase-inversion point of base oil, the phase-inversion point increased with different proportions of asphaltene, resin, and wax. Particularly, at the ratio of asphaltene/resin/wax = 1:5:9, the phase-inversion point reached as high as 80%, indicating the optimal state. In this proportion, asphaltene aggregates exhibited the smallest and most uniform size, best dispersion, lower interfacial tension, and higher interfacial modulus. These findings provide reference and guidance for further enhancing oil recovery in medium-to-high-water-cut thin-oil reservoirs.

Heavy oil in this work is typical acidic heavy oil with acid number larger than 1, which is prone to form W/O emulsions with high viscosity and cause low oil recovery factor during water flooding. In order to further improve oil recovery of acidic heavy oil after water flooding, this paper proposed the in situ O/W emulsion flooding to conversely transform W/O emulsions into O/W emulsion with lower viscosity. Firstly, emulsion system compounding (SDS:L5 = 1:1) named ISEMF was comparatively obtained, which could decrease IFT into magnitude of 10(-2 )mN/m and inversely form stable O/W emulsions with low viscosity. The emulsion evaluation experiment indicated that W/O emulsion would be reversed into O/W emulsions when ISEMF concentration and water content were larger than 0.4% and 30%. Core displacement experiments showed recovery factor increment firstly increased and then decreased with permeability, and there was optimal permeability range for in situ emulsion flooding. The main reason was that much lower or larger permeability was not beneficial to good matching of emulsion droplet and pore throat. In addition, it was found that the displacement efficiency of in situ O/W emulsion flooding was better than that of surfactant flooding under the same conditions, which further validate excellent EOR performance of in situ O/W emulsion flooding for acidic heavy oil.

In recent years, gel plugging agents had made significant contributions to addressing water channeling and water flooding issues in water-flooded oil reservoirs. To meet the demands of unconventional and complex oil reservoirs for profile control and water blocking processes, the performance and adaptability requirements of gel-based profile control agents were increasingly stringent. This paper summarized the macroscopic effects and microscopic mechanisms of different types of gel plugging agents in the processes of “injection, migration, plugging, and stabilization”, explored the shortcomings of existing research, and innovatively proposes directions for future research. Firstly, existing gel plugging agents faced challenges in achieving deep plugging in oil reservoirs with large well-spacing. In response, we proposed an innovative approach using high phase-change stable oil-in-water emulsions as carriers, along with in-situ generated dispersed gel particles under reservoir conditions, to achieve “long-distance and long-lasting” profile control in oil reservoirs with large well-spacing. Secondly, current research mainly focused on enhancing the temperature and salinity resistance of gel plugging agents through the addition of nanomaterials, temperature and salinity-resistant functional monomers or groups, with limited exploration of the microscopic mechanisms. There was a lack of research focusing on the specific locations, patterns, and mechanisms of polymer chain breakage, hindering the targeted resolution of the challenge of polymer gel molecules' long-term profile control difficulty under high-temperature and high-salinity conditions. Lastly, future researches should consider the adsorption losses of gel systems in complex reservoirs, design their composition and dosage, establish adsorption prediction models, simulate the loss mechanisms and quantities in reservoirs, and determine the minimum concentration required for effective plugging. These research outcomes were expected to significantly optimize the performance of profile control agents and drive innovation in the application of gel plugging agents in high-temperature and high-salinity oil reservoirs with large well spacing, providing robust theoretical and practical support for the development of future profile control and water blocking technologies.

In view of heavy oil B which was easy to form W/O emulsion by water flooding, this paper studied the effect of the group components of heavy oil B on the formation and stability of W/O emulsion from the separation of four-component, the characterization of group components, the determination of interface property and the evaluation of emulsion performance. The structure of the group components of heavy oil B was characterized by infrared spectroscopy and synchronous fluorescence spectroscopy. Compared with the other three group components, the asphaltene had strong polarity and high degree of association between molecules. The results of interfacial property measurement showed that asphaltene could reduce the interfacial tension of simulated oil and formation water to 10 degrees orders of magnitude and increase the interfacial expansion modulus by about 1.4-2.6 times compared with the other three group components. This was because asphaltene had strong polarity and complex aromatic structure. In order to further verify the influence of crude oil group components on the formation and stability of W/O emulsion, this paper systematically evaluated the particle size distribution and stability of emulsion formed by different group components. Compared with the saturated and aromatic, the emulsion droplets formed by resin and asphaltene simulation oil were smaller and concentrated, and the demulsification time of emulsion was prolonged by about 1.5-8 times. In summary, the influence of crude oil group components on the formation and stability of W/O emulsion was as follows: asphaltene > resin > aromatic > saturated.

This study investigates the effects of asphaltene, resin and petroleum acid on the phase inversion, stability and oil-water interface characteristics of emulsions. First, different ratios of asphaltene, resin, petroleum acid and formation water were emulsified and the emulsion viscosity was measured to obtain the phase inversion point. Through comparative analysis of phase inversion point data under different conditions, we showed that the synergy of asphaltene and resin was the key to the emulsion phase inversion and the best asphaltene to resin ratio was 1:3. Moreover, the addition of petroleum acid would accelerate the phase inversion. Then, the dynamic interfacial tension of oil and water was measured using the rotating drop method. The synergistic effect of asphaltene and resin would decrease the interfacial tension. However, excessive resin would compete with asphaltene for adsorption, which would increase the interfacial tension. The lowest interfacial value was observed when the mass concentration ratio of asphaltene to resin was. Thus, the addition of petroleum acid significantly reduced the interfacial tension of oil and water. Next, the hanging drop method was employed to measure the interfacial tension of oil and water and the expansion modulus was obtained using the oscillatory drop method. Experimental studies have shown that asphaltene influences the expansion modulus more than resin and the synergistic effect of asphaltene and resin increases the expansion modulus. However, the addition of petroleum acid would decrease the expansion modulus towing to the small molecular weight of petroleum acid. Finally, the emulsion stability was determined using the bottle test method. Experiments showed that the synergistic effect of asphaltene and resin would enhance the emulsion stability. However, the addition of asphaltene played a pivotal role in enhancing the emulsion stability. Further, the addition of petroleum acid would severely destroy the emulsion stability.

Heavy oil used in this study was typical acidic heavy oil (high content of petroleum acid) and very prone to generate viscosified W/O emulsions by mixing with formation water. In order to prevent W/O emulsion formation and simultaneously reduce oil viscosity, oil-in-water emulsification was proposed and eventually sodium dodecyl sulfonate (SDS) was selected as the emulsifier due to the excellent viscosity reduction effects. The results showed that SDS could decrease oil-water interfacial tension to a certain extent and change rock wettability from oil-wet to water-wet. In addition, it was found that water content played an important role in the type of generated emulsions and viscosity-enhancing W/O emulsions were still produced at lower water content (20 similar to 30%) even though SDS was added. The displacement experiment proved that injecting SDS solution could effectively enhance oil recover factor of the acidic heavy oil reservoir, compared with water injection.

针对如何在水驱后进一步开发高含水高温油藏,提出了一种表面活性剂就地乳化驱油技术,对油包水(W/O)型乳化剂OB-2体系进行了乳化特性评价及乳状液驱油研究.研究结果表明,随着乳化剂浓度增大,乳液黏度先增大后减小;对于X油藏原油,乳化剂最佳浓度为0.3wt％,在此浓度下,油水界面张力可降低至10-2 mN/m数量级;在水油体积比低于7:3时,乳化剂OB-2可促使油水两相完全乳化,形成高黏度的W/O型乳液,其中,水油体积比为7:3时乳液黏度最大,增黏率高达370％.岩心驱油实验结果表明,均质条件下,水驱后注入0.3PV乳化剂OB-2体系,可提高原油采收率达26.15％;非均质条件下,该乳化体系可在级差低于7.6时表现出良好的流度控制及非均质调控能力,扩大波及体积.

The foam plays an important role in EOR application, while crude oil properties significantly affect foam behavior. In this study we compare the performance of foam generated by two types of surfactant, which in the presence of two light oils. The foaming properties and foam stability, film thickness and emulsified oil effect were fully studied. The final results show that light oil has a positive impact on foam ability of sodium alpha-olefin sulfonate (AOS). However, the alkyl glycosides (APG) did not have the same effect. As the oil saturation increases from 0 to 80%, the light oil has a significant impact on foam stability of APG than AOS. Furthermore, the half-life change degree k is introduced to characterize the change of bulk foam half-life and foam drainage half-life. According to the calculation results, the positive effect of light oil on AOS was reconfirmed. The AOS is more effective in reducing the coalescence of foam and increasing the foam uniformity compared with APG. Moreover, the formation of emulsion has a positive effect on the foam stability. According to the micrograph of foam, the light oil in AOS is emulsified into quite small oil droplets, filling the plateau borders and lamellas. Furthermore, unlike APG, light oil (oil B and C) performed well in thickening the foam film of AOS.

This paper described an investigation into the properties of water-in-heavy oil emulsion and its role in enhanced oil recovery (EOR). Effect of pH and salinity on emulsion stability, droplet size and distribution as well as rheological behavior were researched. Core flooding experiments were conducted to study the role of emulsion on EOR. Results indicated that stability of emulsions decreased as salinity increased. The presence of salt leads to a rise in droplet size and a drop in uniformity of distribution. Besides, emulsion formed at pH of 7 was characterized by the least stability, largest droplet size and unevenest droplet size distribution. An increase or decrease in pH both improved emulsion stability and reduced droplet size. Equally, rheological property of emulsion was greatly affected by salinity and pH. In relatively low shear rate region (<250 s−1), emulsion viscosity decreased as salinity increased; opposite trend was confirmed when shear rate exceeded 250 s−1. As a whole, shear thinning behavior was more pronounced in lower salinity and pH environment. Specifically, Newtonian behavior of emulsions were observed in high salinity and non-acidic condition in shear rate region of 60s−1-400s−1. The core flooding experiments showed that the formation of in-situ emulsion exhibited good mobility control ability, resulting in the improvement of sweep efficiency. In-situ emulsion prolonged the low-water-cut production period, giving rise to the enhancement of heavy oil recovery during waterflooding.

Aim ed at how to develop high temperature reservoir after water flooding, we proposed the in-situ emulsion flooding by injecting surfactant solutions to evaluate the emulsifying property and study on the oil displacement by the emulsion of the OB-2 system for the W/O（water in oil）emulsifier. The results showed that the emulsion viscosity firstly increased and then decreased along with emulsifier concentration. For oil in reservoir-X, the optimal emulsifier concentration was 0.3 wt% at which could make the interfacial tension reduce to 10 -2 mN/m order of magnitude. When the water-oil ratio was lower than 7∶3, the complete emulsification of oil-water happened and the W/O emulsion with high viscosity would form. The maximum emulsion viscosity appearde when the oil-water ratio was 7∶3, with the viscosity increasing rate of as high as 370 %. The results of emulsion flooding indicated that the recovery factor of the homogeneous core could increase another 26.15 % after water flooding by injecting 0.3PV OB-2 system. On the other hand, when the permeability ratio of parallel cores was lower than 7.6, applying the OB-2 system could achieve good mobility control and heterogeneity regulation.

In this research, sodium dodecyl sulfonate (SDS) was selected as emulsifying viscosity reducer through a great number of laboratory experiments and then the effects of salinity and pH on viscosity reduction effects were evaluated. The result showed that higher salinity would result in emulsion viscosity enhancement. Compared with neutral pH conditions (pH =7), both acidic and basic conditions would promote emulsion viscosity reduction. When pH >7, generated O/W emulsions were much more stable than all other emulsions. Detailed compositional characterization of petroleum acid through a high resolution mass spectrometer (FT-ICR MS) proved that carboxylic acid and phenols inside petroleum acid would react with OH- at basic conditions and produce some natural surfactants. Theses natural surfactants could work synergistically with SDS and further improve emulsion stability.

在化学驱过程中,油水的界面扩张流变性对驱油机理和效果的影响极大.本文综述了化学驱体系中表面活性剂、碱和聚合物对油水界面扩张黏弹性的影响规律,重点剖析了不同类型物质在油水界面上的分布特征、相互作用及界面膜结构,分析了时间、频率和浓度等因素与油水界面扩张黏弹性的关系,为研究化学驱的渗流特征、乳化机理、油墙形成、乳液后处理等问题提供参考和依据.

Abstract In this research, an emulsifier formulation named SC-18 for W/O system was screened out and evaluated for feasible application of in-situ emulsion flooding in high-temperature and high-salinity reservoir. Results showed that SC-18 could reduce interfacial tension to 10–2 order of magnitude and change rock wettability from oil-wet to water-wet, which was beneficial to decrease residual oil saturation and improve displacement efficiency. Meanwhile, rheological testing showed that emulsion produced by SC-18 exhibited good temperature tolerance and mechanical stability, which favored mobility control and sweep efficiency enhancement under harsh conditions. In addition, good viscoelasticity of produced emulsions could also improve sweep efficiency by strengthening plugging and diverting effects of emulsion droplets, namely enhancing “Jiamin effects.” By means of natural core flooding and visualized plate model, it was proved that in-situ emulsion flooding with SC-18 could improve both displacement efficiency and sweep efficiency for high-temperature and high-salinity reservoir. Graphical Abstract

To assist in understanding the progress of polysaccharide biopolymers in EOR, this review collects and summarizes the available data for the first time and thoroughly discusses the structure–property–EOR performance relationship from flask to field scale application. Attentions were given to xanthan, scleroglucan, hydroxyethylcellulose (HEC), carboxymethycellulose (CMC), welan gum, guar gum, schizophyllan, and other newly developed family members. This review provides a synopsis of EOR polysaccharides, which are rapidly emerging as eco-friendly and tough injectants compared to synthetic polymers.

Differing from conventional emulsions, water-in-oil (W/O) emulsions are produced with no additional surfactants in this study. The testing results show that both interfacial tension (IFT) and dilational modulus at all salinities and pH are much higher than those of normal emulsions. A high IFT is not good for making emulsions, but a higher dilational modulus will contribute to more stable emulsions. Emulsion stability declines slightly as salinity increases and the most unstable W/O emulsion appears at pH = 7. To deeply understand the effects of salinity and pH on emulsion stability, petroleum acid is extracted and characterized using Fourier transform ion cyclotron resonance mass spectrometry.