Air injection oil displacement technology has attracted increasing attention due to its abundant source availability and low cost. High-pressure air injection (HPAI) has traditionally dominated light oil reservoir development. Recent technological advancements highlight the growing potential of in-situ combustion (ISC) triggered by ignition following air injection in such reservoirs. However, the effectiveness of ISC under varying reservoir conditions, particularly the gas sweep efficiency after ignition, requires further investigation. Using a light oil reservoir from the Huabei Oilfield, China, as a case study, this study conducts an experiment involving ignition following air injection. The experiment clarifies the combustion dynamics and production characteristics. Numerical simulations further analyze the impacts of reservoir permeability, vertical permeability variations, high-permeability streaks, and pre-existing waterflooding on the sweep efficiency after ignition. Results show that ISC in light oil reservoirs achieves stable combustion front propagation. The peak temperature rise of the combustion fronts is slightly lower than that achieved in heavy oil reservoirs using ISC but significantly higher than that with HPAI. The oil displacement efficiency reaches 92.43%. Vertical permeability variations and high-permeability streaks with large permeability contrast significantly reduce gas sweep efficiency. In contrast, homogeneous reservoir permeability levels and pre-injection waterflooding exhibit relatively minor impacts on sweep efficiency. The application of ISC in light oil reservoirs should therefore be evaluated based on specific reservoir conditions to optimize both displacement and sweep efficiencies.

Dry gas, mainly comprised of methane, ethane, and other light alkanes, is a crucial energy source with widespread applications. Accurate surface tension predictions of dry gas constituents are important for the design and optimization of various industrial dry-gas-based systems. In this study, we integrate the linear gradient theory with five Soave-Redlich-Kwong equations of state (SRK EOSs) (including the original SRK EOS and several volume-translated SRK EOSs), leading to the development of various linear-gradient-theory-based surface tension models. Among these five models, the linear gradient theory coupled with the volume-translated SRK EOS proposed in our previous work demonstrates the highest accuracy in predicting the surface tension for the 10 dry gas constituents considered in this study, with an %AAD of 0.90. The linear gradient theory combined with our previously proposed volume-translated SRK EOS also performs best in calculating density profiles among the five surface tension models. Moreover, the previously proposed volume-translated SRK EOS is capable of accurately predicting the saturation properties and exactly replicating the true critical volumes of the 10 dry gas constituents.

The majority of water-flooded oilfields have reached a high water-cut stage, where high-temperature and high-salinity (HTHS) conditions significantly limit the effectiveness of enhanced oil recovery (EOR) techniques. To overcome this challenge, a novel green foam flooding agent, designated SOO, was developed in this study. This composite system consists of sodium cocoylalaninate (SCA), N, N-dimethyldodecylamine-Noxide (OA-12), and the emulsifier OP-10. Through foam volume and half-life experiments combined with Response Surface Methodology (RSM), the optimal formulation was identified as a mass ratio of SCA: OA-12: OP-10 = 3:2:3, with a total concentration of 0.4 wt%. SOO demonstrated outstanding overall performance under HTHS conditions (150 degrees C, 14,500 mg/L salinity). An low oil-water interfacial tension (IFT) of 0.10288 mN/m was achieved, which facilitates the mobilization of residual oil by reducing interfacial resistance. In addition, foam stability was significantly enhanced, as reflected by an average foam diameter growth rate of only 15.13%, considerably lower than the 18.52% observed for SCA alone. This indicates effective suppression of Plateau border expansion. A high foam resistance factor of 40.0 was also recorded, confirming excellent plugging capacity in high-permeability channels. Sand pack flooding tests verified that SOO improves oil recovery by 23.0% over water flooding, while reducing water cut by 40%. The superior performance is attributed to molecular synergy through hydrogen bonding and dense interfacial packing: SCA and OP-10 act as foam stabilizers that enhance film toughness, whereas OA-12 functions as an efficient foaming promoter. These findings underscore the potential of SOO as an environmentally friendly and high-performance foam flooding agent for enhancing sweep efficiency under HTHS conditions in high water-cut reservoirs. The current formulation exhibits limitations due to the presence of OP-10. Future studies should focus on developing a fully biodegradable and natural foaming agent.

This study selected four viscosity reducers for comparative analysis: dodecyl trimethyl ammonium bromide (DTAB), sodium dodecyl benzene sulfonate (SDBS), alkylphenol ethoxylate (OP-10), and a composite system of nanosilica with alkylphenol ethoxylate (NANO-OP10). Through basic performance tests, different viscosity reducers were evaluated, with a focus on the synergistic effects of nanoparticle and viscosity reducer on emulsification and viscosity reduction in heavy oil. The results indicate that the nano-emulsified viscosity reducer NANO-OP10 demonstrated superior performance in reducing oil-water interfacial tension (IFT), improving emulsification efficiency, and enhancing emulsion stability. Based on comprehensive consideration of both fundamental performance and economic feasibility, the 0.4 % NANO-OP10 was selected for subsequent experiments. In subsequent sand-pack flooding experiments, the primary nano-viscosity reducer flooding increased the oil recovery rate by 12.8 %. A 12-h shut-in period allowed oil-water redistribution, followed by secondary viscosity reducer flooding, which further enhanced the recovery rate by 24 %. After two rounds of viscosity reducer flooding, the overall oil recovery increased significantly, reaching 55.1 %, demonstrating the excellent viscosity reduction and emulsification capabilities of NANO-OP10, along with its remarkable oil displacement performance. Parallel dual-tube sand-pack experiments and microfluidic experiments further validated that the nano-viscosity reducer NANO-OP10 effectively suppresses unstable fingering phenomena, reduces oil-water mobility ratios, enhances emulsification and mobilization of residual oil, and significantly enhances both sweep efficiency and oil recovery. This study presents an economically viable chemical-based viscosity reduction and displacement technology for efficient exploitation of heavy oil resources.

Underground hydrogen storage (UHS) in geological formations is a critical enabler for large-scale energy buffering, yet its feasibility and operational safety hinge on the accurate characterization of interfacial tension (IFT) between hydrogen–cushion gas mixtures and formation brines. Experimental determination of IFT under dynamic reservoir conditions is technically challenging and cost-prohibitive, particularly when addressing the complex geochemistry of subsurface fluids. To address these limitations, this study introduces a robust hybrid machine learning framework designed to predict IFT across a broad spectrum of pressures, temperatures, gas compositions, and, crucially, diverse electrolyte systems including monovalent, divalent, and mixed salts. A comprehensive dataset of 2689 experimental measurements was compiled to ensure robust thermodynamic and compositional coverage. The framework integrates two advanced metaheuristic algorithms—the IVY Algorithm (IVYA) and Osprey Optimization Algorithm (OOA)—to optimize XGBoost, CatBoost, and BPNN architectures. Among the developed paradigms, the IVYA-CatBoost model achieved state-of-the-art predictive accuracy (R2 = 0.9991, RMSE = 0.29 mN/m, AARD = 0.37%) and demonstrated superior generalization capabilities, effectively capturing the non-linear physicochemical effects associated with different ionic environments. SHapley Additive exPlanations (SHAP) analysis confirmed the model's physical consistency, revealing the dominant roles of thermodynamic parameters and gas composition while correctly delineating the positive influence of ionic strength on interfacial forces. Furthermore, Conformalized Quantile Regression (CQR) was employed to quantify predictive uncertainty, generating calibrated 95% predictive intervals. These intervals enable the estimation of conservative safety margins for capillary sealing capacity in various caprocks, facilitating rigorous risk assessment. This work provides a reliable, interpretable, and scalable tool for IFT prediction, supporting the design and optimization of efficient UHS systems in heterogeneous subsurface environments.

The key factors governing the development performance of in-situ combustion (ISC) are not yet fully understood. In this work, , a reaction kinetics model was developed on the basis of the combustion tube (CT) results, which was then integrated into the Computer Modeling Group (CMG) STARS reservoir simulation software by adjusting stoichiometric numbers, kinetic parameters, and reaction enthalpy to match the CT data obtained. Subsequently, a systematic numerical simulations analysis was conducted to investigate the effect of crude oil viscosity on the temperature, oil-gas-water saturation, coke deposition, and enhanced oil recovery (EOR) during ISC. Additionally, a comparative analysis of N2 flooding, flue gas flooding, and ISC was further conducted to elucidate the role of flue gas on EOR. The results demonstrated that higher crude oil viscosity enhanced coke deposition intensity, expanded the coke deposition area, and intensified combustion. However, the condensation effect induced by reservoir water inhibited the propagation range of the combustion front. Furthermore, increased crude oil viscosity intensified the blocking effect of oil bank and reduced its propagation velocity. The elevated viscosity also affected the vertical distribution of the oil bank by affecting gas override and gravity segregation, resulting in faster advancement in the upper reservoir section compared to the lower section. As the crude oil viscosity increased, the unswept oil area at the reservoir bottom expanded accordingly. In contrast, the oil bank formed by heavy oil with lower viscosity exhibited more uniform vertical distribution. And its combustion exhibited more intensive phase changes, which generated an evaporation zone with broader coverage and faster advancement, resulting in earlier production response and higher oil production rates. Additionally, the simulation results indicated that both N2 flooding and flue gas flooding-with thermal effect excluded-resulted in EOR below 3%. Meanwhile, the thermal effect produced by combustion contributed more than 90% to EOR, which constituted the primary mechanism responsible for EOR in ISC processes. This study provides a theoretical basis for future evaluation and decision-making regarding ISC application in heavy oil reservoirs.

This study systematically evaluates the feasibility of transitioning to in-situ combustion (ISC) in a light oil reservoir during its late stage of water flooding, which is characterized by high water cut and low recovery efficiency. Using a specific block in the Daqing Oilfield, China, as a case study, this work investigates the feasibility of ISC through one-dimensional combustion tube experiments and numerical simulations. The experimental results demonstrate that even at a water cut of 98%, ISC can achieve successful ignition and maintain stable combustion front propagation. Based on the production profiles, the ISC process after water flooding can be divided into three distinct phases: the water drainage phase, the plateau production phase, and the production decline phase. The combined application of water flooding and ISC results in a cumulative oil recovery exceeding 90%, demonstrating the strong adaptability of ISC to light oil reservoirs with high water cut and low oil recovery efficiency. Numerical simulations further reveal that ISC effectively enhances oil recovery with low sensitivity to the transition timing, indicating that earlier ISC implementation can yield better economic returns. Moreover, increasing the air injection rate can significantly enhance the oil production rate and shorten the operational period while maintaining a comparable ultimate oil recovery. These findings provide theoretical and technical guidance for optimizing ISC applications after water flooding in light oil reservoirs.

Accurate prediction of CO2 solubility in brine is critical for evaluating the capacity and safety of geological carbon storage. While machine learning offers promise, existing studies are constrained by limited data sets that seldom encompass multicomponent impure CO2 (containing CH4 and N2) in pure water and NaCl brine and often overlook computational efficiency in model optimization. To address these gaps, this study introduces a novel hybrid framework that integrates the LightGBM model with two advanced metaheuristic optimizers-the Ivy Algorithm (IVYA) and the Gaussian-mapping-enhanced Hiking Optimization Algorithm (GHOA). These optimizers are specifically employed to efficiently navigate the high-dimensional, nonconvex hyperparameter space of tree-based models, enhancing global search capability and mitigating premature convergence. Trained on a comprehensive impurity-inclusive brine database, the resulting IVYA-LightGBM model achieved the best performance on the test set (R 2 = 0.9920, MAE = 0.0008 mol/mol, AARD = 7.23%, RMSE = 0.0016 mol/mol) and demonstrated the most outstanding runtime performance and minimal memory consumption. SHAP analysis identified pressure, solute system, and temperature as the dominant factors governing solubility. This work highlights that coupling large-scale, complex-system data with next-generation optimization algorithms is key to developing highly accurate and efficient predictive tools for CO2 sequestration.

Downhole Electric Heating (DEH) offers a promising solution for heavy oil recovery by reducing in-situ viscosity. However, the complex, transient heat transfer mechanisms within multilayered wellbore structures remain poorly understood, hindering system optimization. This study addresses this gap through an integrated experimental and theoretical investigation using a novel full-scale high-pressure/high-temperature simulator (10 MPa, 650°C) equipped with 25 sensor points. A systematic experimental matrix was conducted to isolate the effects of pressure, annular fluid, heater eccentricity, and heating strategy. Results reveal that increasing pressure in gas-filled annuli suppresses natural convection, creating a counter-intuitive "thermal insulation effect" that delays radial heat propagation. Replacing nitrogen with water in the annulus enhances heat transfer efficiency by 2.8–3.4 times, primarily due to nucleate boiling. Heater eccentricity, especially direct tubing-wall contact, reduces total thermal resistance by approximately 74%, markedly accelerating heat transfer. Based on transient heat conduction theory and experimental data, an optimized three-stage heating strategy (high-power breakthrough, adaptive regulation, and steady-state maintenance) is proposed and mathematically formulated. This work provides quantitative correlations and actionable insights for DEH system design and intelligent, energy-efficient field operation, bridging the gap between idealized models and practical applications.

Currently, the development of oil reservoirs with high water cut faces numerous challenges, including poor economic efficiency, difficulties in residual oil recovery, and a lack of effective development technologies. In light of these issues, this paper conducts research on gas drive development during the high water cut stage in middle–high permeability reservoirs and introduces an innovative technical approach for air thermal miscible flooding. In this study, the Enhanced Oil Recovery (EOR) mechanism and the dynamic characteristics of thermal miscible flooding were investigated through laboratory experiments and numerical simulations. The N2 and CO2 flooding experiments indicate that gas channeling is likely to occur when miscible flooding cannot be achieved, due to the smaller gas–water mobility ratio compared to the gas–oil mobility ratio during the high water cut stage. Consequently, the enhanced recovery efficiency of N2 and CO2 flooding is limited. The experiment on air thermal miscible flooding demonstrates that under conditions of high water content, this method can form a stable high-temperature thermal oxidation front. The high temperature, generated by the thermal oxidation front, promotes the miscibility of flue gas and crude oil, effectively inhibiting gas flow, preventing gas channeling, and significantly enhancing oil recovery. Numerical simulations indicate that the production stage of air hot miscible flooding in reservoirs with middle–high permeability and high water cut can be divided into three phases: pressurization and drainage response, high efficiency and stable production with a low air–oil ratio, and low efficiency production with a high air–oil ratio. These phases can enable efficient development during the high water cut stage in medium to high permeability reservoirs, with the theoretical EOR range expected to exceed 30%.

As global demand for crude oil increases, the problem of steam channeling faced in the thermal recovery of heavy oil reservoirs seriously affects the oil recovery and operation cost. Due to the limitations of profile control in traditional foams, the aim of this experimental investigation is to develop a high-temperature-resistant gel foam system to plug steam channeling paths. Gel foam can compensate for the defect of poor thermal stability in single-component foam, and shows great potential in oil reservoir development. This paper mainly expounds that the gel foam system (0.5 wt% foaming agent AOS + 0.5 wt% polymer HPAM + 0.4 wt% crosslinker PE + 0.5 wt% stabilizer), as a profile control agent for improving the recovery, has better performance than the single foaming agent AOS. Through the experiments on the foam volume and the half-life of liquid separation, the foaming agent AOS has the highest foam complex index both at room temperature and under the high temperature condition of 200 degrees C. Subsequently, AOS is selected to be compounded with the gel, and the formula of the gel foam system with good gel-forming performance is determined: 0.5 wt% AOS +0.5 wt% HPAM +0.4 wt% PE + 0.5 wt% stabilizer. In the profile control experiment, when the gas-liquid ratio is 1:1, the addition of AOS to the gel can increase its resistance factor by 14 times, which confirms that compared with AOS, this system can effectively block the high-permeability dominant channels and improve the sweep volume, demonstrating great potential for enhancing oil recovery. Moreover, after the gel foam system is aged at 200 degrees C for 48 h and then subsequent water flooding of 15 PV is carried out, the plugging rate of the gel foam system is still as high as 86.4 %, which also indicates that this system can carry out long-term and effective profile control. Moreover, the heavy oil recovery of the gel foam slug is 6.3 % higher than that of the AOS slug. Therefore, as a profile control agent for improving the sweep efficiency, the gel foam system has greater advantages than AOS profile control.

Injecting industrial high-temperature flue gas into hydrocarbon reservoirs has emerged as a novel approach for carbon sequestration. However, the complex high-temperature phase behavior between flue gas (CO2, N2) and reservoir fluids challenges this technology’s development, as traditional experimental methods and theoretical models often fall short in capturing it accurately. To address this, molecular dynamics simulations were employed in this study to investigate the phase behavior of single-component alkanes, multicomponent alkane mixtures, and multicomponent alkane–flue gas systems under high-temperature conditions. The results reveal that CO2 can become miscible with alkanes, while N2 diffuses into the system, causing volumetric expansion and a reduction in density. The initially distinct phase interface between the multicomponent alkanes and the flue gas becomes progressively blurred and eventually disappears, indicating the formation of a fully miscible phase. Comparative simulations revealed that the diffusion coefficients of N2 and CO2 increased by up to 20% with rising temperature and pressure, while variations in flue gas composition had negligible effects, indicating that high-temperature and high-pressure conditions significantly enhance flue gas–alkane miscibility.

Air injection for enhanced oil recovery (EOR) is an important replacement technology for low permeability reservoirs. Most low permeability reservoirs undergo fracturing during development, so it is necessary to further study air injection to EOR in fractured low permeability reservoir. In this paper, crude oil oxidation experiment is used to simulate the change of regional crude oil oxidation temperature during air injection, and the temperature of injected air and crude oil oxidation is obtained. At the same time, the advancing velocity and advancing law of oxidation thermal front and gas front around formation fractures are simulated by numerical simulation. Based on the results of oxidation experiment and numerical simulation, the influence of underground fractures on the shape of underground temperature field and the temperature of oxidation front is obtained, the displacement characteristics of air injection development technology in fractured reservoirs are formed, and the stable underground oxidation reaction and stable advancing law are determined, In this paper, the displacement characteristics of air injection to EOR in fractured low permeability reservoir is confirmed, which lays a foundation for the popularization and field application of air injection EOR technology.

CO2 2 nonequilibrium dissolution in heavy oil was thoroughly studied, and the relevant mass-transfer parameters were determined. Experiments were conducted at different scales, including a single ultrathin microfluidic channel and ultrathin bulk-phase cell. A continuum-scale simulator coupled with an external real-time programing command was developed to determine the mass-transfer parameters, including the intraphase effective diffusion coefficients and interphase nonequilibrium mass-transfer rates. The former were correlated with the solvent concentration and chemical potential of the system, while the latter were calculated using nonequilibrium chemical potential decay, which was correlated with the system pressure and free energy. The newly developed simulator was verified using literature data from various experimental scales, including PVT cells and microfluidics. The simulator incorporates the effect of nonequilibrium free energy on interphase mass transfer in quiescent molecular diffusion-dominated processes, providing a viable technique for accurately simulating continuum-scale mass transfer, particularly in solvent-based injection.

Alkali-surfactant-polymer (ASP) flooding is a chemical enhanced oil recovery method; its working mechanisms include mobility control, wettability alteration, and in-situ emulsification. However, conventional alkalis used in the ASP flooding could cause some serious issues, including scaling, formation damage, and pipe corrosion. In this study, we investigated the feasibility of incorporating organic alkalis as chemical additives in hot water flooding to enhance heavy oil recovery. The focus was on studying the interfacial properties, that is, interfacial tension (IFT) and wettability, emulsification mechanisms, thermal stability of alkalis, and recovery efficiency through coreflooding experiments. Three organic alkalis, including diethylamine (DEA), ethanolamine (ETA), and triethlymine (TEA), were selected to evaluate their potentials in enhancing heavy oil recovery and investigate their recovery mechanisms. Coreflooding experiments were conducted at 50 degrees C and 2 MPa with sandpacks saturated with a high total-acid-number (TAN) heavy oil sample. The measurement results demonstrated that all three organic alkalis could effectively reduce the IFT between water and heavy oil from 22.7 to 1.6 mN/m and favourably alter the wettability of rock surface. ETA exhibited good thermal stability up to 100 degrees C in hot water applications. The interaction between organic alkalis and heavy oil could generate either water-in-oil or oil-in-water emulsions, depending on the water-oil ratio (WOR). The coreflooding experiments showed a significant increase (16%-17.5%) in heavy oil recovery using ETA for two distinct injection strategies. IFT reduction, wettability alteration, and emulsification were found to be the main recovery mechanisms when organic alkalis are utilized as chemical additives for hot water flooding.

Thermal miscible flooding has shown promise in enhancing light oil recovery from gas condensate reservoirs. In this process, the generated flue gases could become miscible with gas condensate under elevated reservoir temperatures. To study the miscibility behavior between flue gas and gas condensate, we develop a thermodynamic model based on the Peng-Robinson equation of state (PR EOS) coupled with Peneloux volume translation, for a benchmark gas condensate sample. The pseudocomponents' properties are tuned to match the constant composition expansion (CCE) and the constant volume depletion (CVD) test data. The tuned model can well reproduce measured data (e.g., relative volume and liquid dropout) in these tests. We then apply it to calculate the phase envelopes of N2-gas condensate, CO2-gas condensate, and CO2-N2-gas condensate mixtures, revealing the shifts in original phase envelopes. Next, to investigate the influences of temperature and flue gas composition on miscibility behavior, we utilize the analytical tie line method and the cell-to-cell method to calculate the MMPs and drive types of different flue gas-gas condensate mixtures. It is found that the MMP of a given injection gas first increases with temperature, reaches a peak, and then decreases. The dimensionless fraction of vaporizing mechanism of a given injection gas decreases with temperature. The highest MMPs of CO2 and N2 are 506 bara at 350 degrees C and 620 bara at 250 degrees C, respectively. If the flue gas contains more N2, the peak MMP and the dimensionless fraction of vaporizing mechanism increase, but the temperature corresponding to the peak MMP is reduced.

A high-temperature and high-pressure experimental device was upgraded to accommodate a maximum pressure of 40 MPa and a maximum temperature of 800 °C. Using this experimental device, one-dimensional oxidation displacement experiments were carried out via air injection in the Hudson original reservoir to change the pressure from low pressure (5 MPa) to high pressure (30 MPa) and via air injection after water injection under 30 MPa high-pressure conditions. A stable medium–high-temperature thermal oxidation front and displacement state could be formed in the experiments under different pressure measurements of 5 MPa, 15 MPa, and 30 MPa and in the air injection experiment after water injection under high pressure, at 30 MPa, which was similar to the oxidation front and displacement characteristics of heavy oil air injection in situ combustion. However, as the pressure increased, the air consumption and fuel consumption became smaller, and the temperature of the oxidation front became lower. And compared with the original reservoir, the air consumption and fuel consumption of air injection after water injection increased, and the temperature of the oxidation front became higher. This was completely different from the law of heavy oil in situ combustion. With the increase in pressure, the pore volume number (PV) of the injected air was smaller, the gas production/injection ratio was smaller, and the oil displacement efficiency was higher. Therefore, the stability of the 30 MPa high-pressure air injection displacement was better. The gas/oil ratio (GOR) produced by 30 MPa air injection after water injection in the experiment was stable, and air injection after water injection could reduce the water cut and greatly improve oil displacement efficiency. Therefore, air-injection-enhanced oil recovery technology was still feasible in the reservoir after water injection.

The in situ conversion of oil shale with air injection has the advantage of self-generated heat. The fragmentation degree of oil shale affects the oxidative pyrolysis process. In this paper, the basic properties of oil shale were analyzed, and weight loss observation and high-pressure TGA-DSC (thermogravimetric analysis and differential scanning calorimetry) tests in an air atmosphere were conducted using the cores and particles. The oil shale’s oxidative pyrolysis characteristics and the effect of its particle sizes were evaluated. The results show that the porosity and permeability conditions, TOC (total organic carbon), and inorganic mineral composition of oil shale are highly heterogeneous, with higher permeability and greater TOC along the bedding direction. The derivative of the TGA curve shows a single peak, and the heat flow curve shows a double peak that can be used to determine the oil shale’s oxidation type. The oxidative pyrolysis stage of organic matter can be divided into three temperature ranges, of which the medium temperature range is where the most combustion weight loss and heat release occurs. The activation energy of oxidative pyrolysis, which is affected by factors such as particle size, organic matter content, and pyrolysis temperature, is 46.92–248.11 kJ/mol, indicating the varying degrees of difficulty in initiating the reaction under different conditions. The pre-exponential factor is 3.15 × 102–6.27 × 1011 1/s, and the enthalpy value is 2.575–4.045 kJ/g. The combustion indexes and reaction enthalpy under different particle sizes are more correlated with their own organic matter content. As oil shale particle size decreases, the variation law of the activation energy and pre-exponential factor changes with temperature from an initial continuous increase to a decrease, then increases again with the smallest kinetic parameters in the medium temperature zone. A small particle size, high organic matter content, and high pressure are more conducive to initiating the oxidative pyrolysis reaction to achieve in situ conversion of organic matter.