• Energy Research

Abstract. The considerable decline of conventional oil and gas reserves and respectively their production introduces new challenges to the energy industry. It resulted in the involvement of hard-to-recover reserves using advanced enhanced oil recovery (EOR) techniques. Thermal methods of EOR are recognized as most technically and commercially developed methods for the highly viscous crude oil. High-Pressure Air Injection (HPAI) is one of the thermal production methods that reduce oil viscosity and increases recovery. HPAI has already been effectively applied for different types of reservoirs development and proven to be economically feasible. The application performance of the HPAI technology strongly depends on the quality of experimental and numerical modeling conducted on the target object basis. Before the field tests, physicochemical and thermodynamic characteristics of the process were studied. Further consequent numerical modeling of laboratory-scale oxidation experiments and field-scale simulation was conducted to estimate HPAI method feasibility based on the results of oxidation studies. A medium pressure combustion tube (MPCT) oxidation experiment was carried out to provide stoichiometry of the reactions and field design parameters. A 3D numerical model of the MPCT experiment was constructed taking into account the multilayer design, thermal properties, heating regimes, and reaction model. The “history” matched parameters such as fluid production masses and volumes, temperature profiles along the tubes at different times and produced gas composition demonstrated good correspondence with experimental results. The results obtained during the experiment and modeling of MPCT (fluid properties, relative phase permeability, kinetic model, technological parameters) were used in field-scale modeling using various thermal EOR scenarios. Air breakthrough into production wells was observed, thus a 2 % oxygen concentration limit where implied. The overall performance of four different scenarios was compared within 30 years timeframe. The development system was also examined to achieve the maximum economic indicators with the identifications of risks and main uncertainties.

A tremendous amount of fossil fuel is utilized to meet the rising trend in the world’s energy demand, leading to the rising level of CO2 in the atmosphere and ultimately contributing to the greenhouse effect. Numerous CO2 mitigation strategies have been used to reverse this upward trend since large-scale decarbonization is still impractical. For multiple reasons, one of the optimal and available solutions is the usage of old depleted oil and gas reservoirs as objects for prospective CO2 utilization. The methods used in CO2 underground storage are similar to those used in oil exploration and production. However, the process of CO2 storage requires detailed studies conducted experimentally and numerically. The main goal of this paper is to present an overview of the existing laboratory studies, engineering and modeling practices, and sample case studies related to the CCS in oil and gas reservoirs. The paper covers geological CO2 storage technologies and discusses knowledge gaps and potential problems. We attempt to define the key control parameters and propose best practices in published experimental and numerical studies. Analysis of laboratory experiments shows the applicability of the selected reservoirs focusing on trapping mechanisms specific to oil and gas reservoirs only. The current work reports risk control and existing approaches to numerical modeling of CO2 storage. We also provide updates on completed and ongoing CCS in oil and gas reservoir field projects and pilots worldwide.

Abstract High-Pressure Air Injection (HPAI) as an enhanced oil recovery (EOR) method has a high potential and has already been effectively applied for carbonate reservoirs development. The target object of the current research is a Kirsanovskoe oil field confined to the North Kinelsky oil and gas region. Kirsanovskoye field is a carbonate reservoir with an average depth in the range of 1300–1350 m, average porosity of 11.5%, and average permeability of 70.6 mD. The HPAI process, which includes intensive oxidation and combustion reactions, phase transitions of components and change in the composition and properties of coexisting phases, is not fully explored yet. Its complexity and lack of reliable chemical and kinetic models both for light and heavy oils cause several limiting factors for the construction of a field numerical model with the high predicting level in the respect to the HPAI as the EOR method. The presented work is devoted to the construction and validation of laboratory-scale numerical models of oxidation experiments to provide proper HPAI kinetic model for oxidation and combustion reactions for the Kirsanovskoye oil field. For these purposes, high-pressure ramped temperature oxidation (HPRTO) and subsequent Medium pressure combustion tube (MPCT) experiments were conducted and analyzed. HPRTO test is used for the determination of the reaction kinetics together with such characteristics as a function of temperature, O2 uptake, CO2 generation, oxidation front velocity, peak temperatures, residual coke, and amount of burned and recovered oil. MPCT provides information on stoichiometry for the high-temperature process and optimal airflow rate. A significant part of the research is dedicated to the construction of 3D numerical models (multilayer design, proper heater regime, etc.) of HPRTO and MPCT experiments to avoid constructional uncertainties and their further validation against the experimental data. To describe the chemical behavior of hydrocarbons during the HPAI process we use the reaction scheme which includes polymerization of Malthenes and Asphaltenes in low-temperature oxidation region, thermal cracking and coke combustion in the high-temperature oxidation region.

The work presented herein is devoted to a unique set of forward and reverse combustion tube (CT) experiments to access the suitability and potential of the in situ combustion (ISC) method for the light oil carbonate reservoir. One forward and one reverse combustion tube tests were carried out using the high-pressure combustion tube (HPCT) experimental setup. However, during reverse combustion, the front moved in the opposite direction to the airflow. The results obtained from experiments such as fuel/air requirements, H/C ratio, and recovery efficiency are crucial for further validation of the numerical model. A quantitative assessment of the potential for the combustion was carried out. The oil recovery of forward combustion was as high as 91.4% of the initial oil in place, while that for the reverse combustion test demonstrated a 43% recovery. In the given conditions, forward combustion demonstrated significantly higher efficiency. However, the stabilized combustion front propagation and produced gases of reverse combustion prove its possible applicability. Currently, there is a limited amount of available studies on reverse combustion and a lack of publications within the last decades despite advances in technologies. However, reverse combustion might have advantages over forward combustion for heavy oil reservoirs with lower permeability or might serve as a reservoir preheating technique. These experiments give the opportunity to build and validate the numerical models of forward and reverse combustion conducted at reservoir conditions and test their field application using different scenarios.