In-situ combustion technology (ISC) was a potential technology for efficient development of medium-low maturity shale oil reservoirs. Clarifying the exothermic behavior of organic carbon oxidation will be beneficial for better control of ISC processes. In this work, the organic carbon composition, type II kerogen and residual oil, were separated and extracted from the shale samples of typical medium-low maturity shale oil reservoirs in the Ordos Basin, China. The synchronous thermal analyzer and mass spectrometry (STA-MS), Fourier transform infrared spectroscopy (FTIR), and ROCK-EVAL VI were used to study the products, heat release, and functional group changes of type II kerogen, residual oil, and shale during the oxidation process. The results indicated that the oxidation heat release of shale mainly came from the oxidation reaction between its residual oil and type II kerogen, but the oxidation heat release range of shale was relatively lagging compared to the single residual oil or type II kerogen affected by rock debris. Secondly, under atmospheric pressure, the type II kerogen experiences obviously higher heat release than residual oil and heavy oil, indicating its superior potential of in-situ heat release. In addition, the major productions that CO, H2O, 2 O, SO2, 2 , and CO2 2 were quantitatively characterized, with CO2 2 having the highest production of 882.25 mg/g. Furthermore, combined with the molecular weight, an oxidation reaction equation of type II kerogen was constructed. Finally, the oxidation kinetics parameters of type II kerogen, residual oil, and shale were determined using Friedman and Ozawa-Flynn-Wall (OFW) models. It was found that the activation energy of shale was higher than II kerogen and residual in low temperature oxidation (LTO) and fuel deposition (FD) stages. This may be due to the joint reaction between kerogen and residual oil, thus exacerbating the challenge of shale in-situ ignition. However, due to the catalytic effect of rock debris, the activation energy of shale was lower than LTO in high temperature oxidation (HTO) stage, indicating that once fuel deposition was completed, organic carbon will undergo stable combustion. This study has theoretical guidance for the numerical simulation research of ISC development technology of maturity-low shale oil reservoirs.

Hydrogen is a clean energy and plays an increasingly important role in the energy field. Hydrogen production from natural gas is an important source of hydrogen, but it is also accompanied by carbon emissions. It is beneficial to move the natural gas hydrogen refining site to the underground oil and gas reservoirs that are difficult to develop. The complex reservoir structure of gas reservoir is a challenge to hydrogen production from underground natural gas. In this paper, CMG Stars software is used to simulate methane combustion and in situ hydrogen production reaction in multiple storage media, and explore the influence of geological parameters and injection parameters on hydrogen production efficiency of gas reservoirs. The simulation results show that, the fracture reconstruction area is the main place for hydrogen production reaction, the better hydrogen production efficiency can be obtained when the matrix permeability is less than 0.1 mD, and hydrogen production efficiency can also be improved with the increase of injected oxygen concentration and injection amount. The research results have clarified the reaction space of in-situ hydrogen production from natural gas and the factors affecting the efficiency of underground hydrogen production. It will provide a basic reference for the implementation of this technology..

Magnetic nanomaterials, known for their eco-friendliness, low toxicity, strong magnetic response, and reusability, have seen significant advancements in enhancing oil recovery. In this study, the surfactant and magnetic Janus nanoparticles (MJNP) were evaluated and optimized through Fourier transform infrared spectroscopy, zeta potential test, scanning electron microscope, emulsion performance evaluation and other analysis, so as to develop magnetic Janus nanofluids (MJNF). Study the flow behavior and enhanced oil recovery mechanism of this nanofluid in porous media through nuclear magnetic resonance (NMR) and numerical simulation methods. The results showed that when the concentration of surfactant (LAD-30) was 0.08%, the maximum water content of emulsion was 80%, and the viscosity increased by more than 90000%. In addition, when the MJNP concentration is 400 ppm or higher, a stable emulsion is formed at 90 degrees C. NMR experiment shows that through MJNF oil displacement, the oil recovery of small and medium-sized pores is significantly improved by 25.9% and 18.3%, which indicates that high viscosity emulsion can be formed in situ after MJNF injection, thus achieving consistency control. In addition, the numerical simulation results also found that MJNF injection can improve the oil-water saturation in the pore volume and enhance oil phase flow. The research results provide a new understanding for EOR of emulsion flooding.

The large volume of injected water flowed along the high permeability zone, which led to serious problems in the middle and late stages of flood development in ultra-low permeability fractured reservoirs. In this paper, we developed a novel gel-foam plug by using silica gel as a liquid phase dispersing medium for foam, evaluated and optimized the foaming and gelation performance of the gel-reinforced foam system. The gas-to-liquid ratio, injection volume, injection concentration, injection speed, and injection mode of the plugging agent were optimized by core-flooding experiments, and oilfield tests were conducted in oil fields. The plugging agent was formulated as follows: 5

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 situ combustion (ISC) is a primary technique used to enhance oil recovery in heavy oil reservoirs. By performing controlled burning of the oil in place, the heavy oil is expected to be lighter and easier to flow. Conventional studies mainly considered the viscosity reduction during this process. This ISC process may change the fluid-rock wettability. However, the role of wettability alteration is not well investigated during ISC. To fill this knowledge gap, we performed ISC and measured the dynamic surface wettability changes under different combustion temperatures. Furthermore, relative permeability curves were interpolated to quantify the effects of wettability changes in heavy oil recovery during ISC. This study revealed wettability change during ISC. As the temperature increases, the contact angle decreases. At firing temperatures of 200, 300, 400, and 500 degrees C, the rock wettability changed to hydrophilicity, with a stronger hydrophilicity observed at higher temperatures. However, at 200 degrees C, the hydrophilicity was not strong. This was due to the low-temperature oxidation of the crude oil at the combustion temperature of 200 degrees C, and the oxidized oil was attached to the rock surface, causing the rock wettability to become hydrophobic. Numerical simulation results demonstrated that the transition from oil-wet to strong hydrophilic wettability is favorable for oil recovery, resulting in an increased recovery factor of 8.75%. This confirms that wettability alteration in the reservoir is one of the main mechanisms for heavy oil recovery during ISC. These findings indicate the influence of reservoir wettability on oil recovery during the ISC process and contribute to further understanding of the ISC mechanism.

This study employed a reverse emulsion method to prepare dispersed nanoparticle gels that respond to mineralization and exhibit excellent characteristics such as small particle size, high dispersion, and strong stability by introducing catechol-like structures and temperature/salt-resistant functional monomers. Experimental results showed that the particle size of the dry dispersed gel particles ranged from tens to 100 nm, as observed by scanning electron microscopy. Laser particle size analyzer testing demonstrated that the size of the dispersed gel particles progressively increased with the mineralization degree of the dispersed particle gel, indicating a certain level of mineralization responsiveness. Additionally, these particles could maintain stable dispersion for up to 40 days in a solution with a mineralization degree of 20,000 mg/L. The rheology testing results indicate that the dispersed particle gels exhibited the properties of the pseudo-plastic fluid. Even under extreme conditions such as high temperature and mineralization, the strength of the dispersed particle gels remained intact, measuring 95.76 kPa after 40 days of aging. Using Materials Studio molecular simulation software, the stability and selfgrowth mechanism of dispersed gel particles were explained from the quantum mechanics perspective. The geometry of the dispersed gel particles was optimized using the Compass II force field, and the total energy of the model was calculated to be -757.579 kcal/mol, with the dihedral torsion energy contributing the most to the total energy. The molecular bond lengths in the polymer chain were then calculated, with the O-H bond being the shortest and the O-Na bond in the carboxylate sodium group being the longest. This indicated that the -OH group was more stable and the carboxylate sodium group was prone to hydrolysis, forming a -COOH group and increasing the dispersion stability. The charge distribution and molecular orbitals in the polymer molecule were also calculated, with the LUMO value being -7.405 eV and the HOMO value being -4.487 eV. This study used a reverse emulsion method to in-situ generate mineralization-responsive, multi-haired dispersed gel nanoparticles, which fundamentally solved the injection problem of low-permeability oil reservoirs and provided new materials for long-term plugging of high-temperature and high-salinity oil reservoirs.

This study focused on the water breakthrough issue that still occurred after water shutoff using gel plugging agents. Taking the heavy oil reservoir with edge-bottom water in the Y oilfield as an example, the study investigated the water cut variations after water shutoff and analyzed the types of water breakthrough characteristics in the wells of this reservoir. The CMG numerical simulation software was used to study the influence of geological parameters on the water cut variations after water shutoff. The research findings revealed that the water breakthrough characteristics in all the treated horizontal wells were classified into low water cut breakthrough, pulse-type breakthrough, step-type breakthrough, and high water cut breakthrough. Additionally, it was observed that horizontal wells in different geological conditions exhibited distinct water breakthrough characteristics under the same water shutoff process conditions. Through numerical simulation and statistical analysis of field data, the main factors influencing the variation of water cut after water shutoff were identified as reservoir permeability, oil saturation, interlayer position, water avoidance height, injection-production well distance, oil viscosity. The research findings allowed for the prediction of water breakthrough characteristics after water shutoff or the analysis of reservoir structure configuration based on known water breakthrough characteristics.