Tatneft (Russia)

The paper presents the results of nuclear magnetic resonance (NMR) study of oil samples taken from production wells from the fields of the Republic of Tatarstan before and after the application of one of the enhanced oil recovery (EOR) methods, namely, flow rejection technology based on injection of microgel compositions into injection wells. A comparative analysis of proton NMR spectra and diffusion attenuation of spin echo in spectrally resolved mode was carried out in order to determine the influence of the used technology on the characteristics of recoverable oil. It is shown that after application of EOR for the majority of wells in the oil composition an increase in the share of hydrocarbon components with large values of molecular weight is registered, and for a number of wells a change in the degree of aromaticity of recoverable hydrocarbons is also recorded. The results obtained are interpreted as a consequence of the inclusion in the development of new reservoir zones, previously not involved in oil production, and demonstrate the potential of NMR method for assessing the efficiency of EOR.

Despite the persistent increase in demand for energy resources, the world maintains abundant reserves of heavy oils, underscoring the continued relevance of research aimed at enhancing their extraction efficiency. This study explores laboratory simulations of aquathermolysis processes and investigates the transformation of oil-containing rock from the Kizelov deposit, both with and without the presence of a sodium nanosuspension, within a water vapor environment at temperatures ranging from 150 to 300 °C. Employing various analytical methods, including determination of gas composition, X-ray fluorescence spectroscopy, SARA analysis, gas chromatography-mass spectrometry, and X-ray diffraction analysis, the research unveils significant insights. Notably, thermal steam treatment (TST) augmented with a sodium suspension proves effective in reducing total sulfur content by 86–95% even at lower temperatures. Moreover, TST at 200 °C, coupled with the introduction of metallic sodium, markedly enhances the concentration of saturated hydrocarbons in the oil by threefold. The addition of a sodium nanosuspension during the hydrothermal treatment of oil-containing rock yields intriguing outcomes in the aromatic fraction of extracts, resulting in the formation of novel compounds, such as alkyl diphenyls, alkyl phenylnaphthalenes, and piperidines, while facilitating the complete elimination of sulfur-containing aromatic compounds. Additionally, the impact of sodium on the mineralogical composition of the rock is elucidated, particularly in the formation of minerals such as portlandite, shortite, and nierereite.

Shale oil is a complex organic rock in which kerogen serves as the main source for obtaining liquid hydrocarbons. Traditional methods of light oil extraction prove to be inefficient due to their low bitumen content and high extraction costs. This stimulates the need for the development of new, efficient, and environmentally friendly technologies for the extraction and processing of shale oil. This article proposes a method of hydrothermal conversion of Domanic shale in subcritical and supercritical fluids at various temperatures (300, 350, and 400 °C). Analysis methods include SARA analysis, gas chromatography, GC/MS of saturated and aromatic fractions, IR spectroscopy, X-ray tomography of rocks, and others. The results confirm changes in the composition and structure of shale, including hydrocarbon redistribution, changes in resins and asphaltenes, and heterogeneous changes in pore space. These data reveal the influence of hydrothermal conversion of Domanic shale, opening new perspectives for understanding and optimizing the processes of synthetic oil production.

The escalating share of hard-to-extract, highly viscous oil poses tangible challenges in the realm of oil extraction. Employing thermal steam treatment (TST) technology presents a promising approach, not only for viscosity reduction but also for comprehensive upgrading of extracted hydrocarbons within the reservoir itself. This study meticulously explores the impact of the TST duration, in tandem with organodispersed metallic sodium, on the upgrading of heavy oil sourced from the Ashalcha field. Through meticulous analysis utilizing gas chromatography, SARA analysis, IR spectroscopy, and GC-MS of individual fractions, the optimal duration for enhancing oil composition was pinpointed: 72 h at a temperature of 250 °C during TST. Remarkably, the utilization of sodium nanoparticles neutralizes hydrogen sulfide and carbon dioxide while concurrently catalyzing the degradation and reduction of asphaltenes, notorious for their adverse impact on oil rheology. Noteworthy findings include a discernible upsurge in low-molecular-weight hydrocarbons within the C1–C4 range, ascertained via gas chromatography. Additionally, analysis of saturated hydrocarbon composition using GC-MS highlighted a decline in compounds characterized by longer hydrocarbon chains. IR spectroscopy unveiled alterations in the asphaltene fraction, exhibiting reduced aromaticity attributable to the unfolding of cyclic structures and the elongation of hydrocarbon chains consequent to TST in the presence of a metallic sodium-based suspension.

The paper analyzes the operation dynamics of injection and observation production wells. It assesses the impact of injection wells on produced water density. The reservoir is characterized by out-contour flooding. It was found that such a scheme is ineffective due to the weak hydrodynamic relationship of the reservoir with the aquifer, which is confirmed by the result of this analysis, and the selective (focal) water flooding used on the Kizelovsky horizon also does not have the proper effect, and there is no correlation of formation pressure with injection in observation wells. It was shown that large volumes of water injection into injection wells do not maintain formation pressure in certain areas, but in general, there is a slight positive impact on the development indicators for the target. The recommendations for optimizing the formation pressure maintenance system were proposed based on the results of the analysis.

The article provides an overview of ion-modified waterflooding technology, also known as low salinity, controlled salinity, or Smart water. This technology is currently considered one of the most promising approaches in the development of oil deposits in carbonate reservoirs due to its economic efficiency and environmental safety. The article discusses the main mechanisms and processes underlying ion-modified waterflooding and presents the results of laboratory studies conducted on core samples from foreign oil deposits. It includes an analysis of several studies, including contact angle measurements and core flooding experiments on core samples from oil deposits in carbonate reservoirs on the eastern side of the Melekess depression in the Republic of Tatarstan. It is important to note that the Vereyian deposits explored in this article are not a typical example of test objects for ion-modified water injection. This is because they are characterized by a low reservoir temperature of 23 °C, which suggests that the efficiency of the technology would likely be lower compared to studies conducted abroad, where reservoir temperatures were significantly higher. For example, Darvish Sarvestani et al. studied reservoir conditions at 90 °C, Yousef et al. – reservoir temperature of 100 °C, and Austad et al. examined the Ekofisk field at 130 °C and the Volhall field at 90 °C in Norway. However, as several studies have indicated, prolonged contact between rock samples and ion-modified water contributes to significant hydrophilization of the rock surface, as confirmed by contact angle measurements. The contact angle decreases from approximately 138.3° to 53.45° after exposure to ion-modified water. Additionally, the core flooding experiment demonstrated a slight increase in the oil displacement coefficient, reaching 9.2%. These findings suggest the potential for enhanced oil recovery by injecting Smart water into the Vereyian sediments, although further research is required to confirm the underlying mechanism.

For the entire production life of a reservoir, oil recovery operations can be divided into three phases: primary, secondary, and tertiary. Enhanced oil recovery (EOR) techniques generally include both the secondary and tertiary methods, and it is not restricted to a particular phase defined previously in the producing life of the reservoir. The purpose of EOR is to increase the production from reservoirs that can be, or have been, produced by primary drive. Thermal EOR methods are most widely used for heavy crudes recovery. Generally, thermal EOR methods include steam injection, in situ combustion, and hot water flooding. All these methods elevate the temperature inside the reservoir to reduce oil viscosity. To achieve a high oil recovery, chemical EOR methods are implemented for some heavy oil reservoirs. Gas EOR methods include immiscible and miscible gas injection. There are several possible EOR mechanisms of microbe injection.

Results are discussed for evaluation of effectiveness of the cyclic geomechanical treatment (CGT) on a Tournaisian carbonate reservoir. Analysis of laboratory experiments performed according to a special program to assess permeability changes for Tournaisian samples under cyclic changes in pore pressure is presented. The main conclusion is the positive selectivity of the CGT: an increase in permeability is observed for samples saturated with hydrocarbons (kerosene) with connate water, and maximal effect is related to the tightest samples. For water-saturated samples, the permeability decreases after the CGT. Thus, the CGT improves the drainage conditions for tight oil-saturated intervals. It is also confirmed that the CGT reduces the fracturing pressure in carbonate reservoirs. Using flow simulations on detailed sector models taking into account the results of laboratory experiments, a possible increase in well productivity index after CGT with different amplitudes of pressure variation was estimated. Results of a pilot CGT study on a well operating a Tournaisian carbonate reservoir are presented, including the interpretation of production logging and well testing. The increase in the well productivity index is estimated at 44-49 % for liquid and at 21-26 % for oil, with a more uniform inflow profile after the treatment. The results of the field experiment confirm the conclusions about the mechanisms and features of the CGT obtained from laboratory studies and flow simulations.

<strong>Abstract</strong> The purpose of the work is to determine the way to work with fracture simulator output data for cases complicated by stage-by-stage processing calculations. Hydraulic fracturing databases are designed to store a single numerical parameter, which causes complications when there are several values in the output data set. The way to obtain a correct estimation of the designated case by a single parameter will allow to apply the results of calculations in the statistical analysis of hydraulic fracturing. Scientific novelty of the work lies in the definition of a new method for working with the output data of the hydraulic fracturing simulator. The scope of application includes the case of formation of several fractures, as well as several calculations relating to one fracture. As a result, a method of working with data has been developed, which allows filling the standardized data set regardless of the number of elements in the output data of the hydraulic fracturing simulator.

Nowadays, oil fields on the territory of the Republic of Tatarstan are developed with application of systems for reservoir pressure maintenance, involving injection of large volumes of water into the formation. Efficiency of waterflooding depends on the quality of the injected agent, and, despite the use of various technologies of preparation and treatment of injected water, with the lapse of time critical matrix porosity and permeability inevitably decreases. In this work the main sources of injection wells critical matrix clogging are considered: mechanical impurities, oil products and scales formation, and the results of the component composition analysis of deposits from cluster pumping stations are given. Using the Oddo-Thomson methodology, it is revealed that injected water is prone to calcite and barite deposition at bottomhole conditions. Physicochemical and core-flooding study of several reagents for removing colmatants: acid compositions, hydrocarbon solvents and complexing agents were carried out and their optimal formulations were determined. The matrix treatment technology, including the sequential injection of compositions based on hydrochloric and mud acids, was substantiated. An algorithm for calculating the optimal reagent volume has been developed on the basis of research data on the mineralogical composition of mechanical impurities and ionic composition of injected water. Four types of matrix treatment technologies were determined for the conditions of injection wells at the Romashkinskoye oil field Devonian formation, taking into account the composition of colmatant, and acid treatment designs were developed.