Oil Formation Research Articles

The facies-genetic type of triassic sediments and the main oil and gas formations of the Mangyshlak peninsula

This paper presents the results of many years of research by the authors. The facies-genetic types of Triassic deposits of the Mangyshlak region have been studied in detail.It is shown that the Triassic and especially the Middle and Upper Jurassic sediments are enriched with more dispersed organic matter than in comparison with the layers below and above. According to the analysis results, the Jurassic and Lower Cretaceous sediments are characterized by abnormal values of dispersed bituminous matter compared to other rocks.The bitumen content is generally low (from 0.01 to 0.5%). Jurassic deposits are characterized by higher values than Lower Cretaceous ones. At the same time, a detailed study of the distribution of organic residues (including faunal remains) gives grounds to classify the entire Triassic-Jurassic-Lower Cretaceous regional oil and gas complex (with the exception of the lower part of the Neocomian and Triassic) as shallow-marine sediments of stable and moderate sedimentation regimes. Oil and gas formations, regional patterns of their distribution in the sedimentary cover of the Mangyshlak region, as well as the adjacent oil and gas region, have been studied in detail. The main oil and gas bearing formations of the Mangyshlak region include the pre-Permian substrate (Devonian, carboniferous), Permian terrigenous-clay and carbonate-chemogenic formation (transitional) (Permian), terrigenous-clay colorful-gray-dark gray-colored (subglenic) (Triassic, Lower Middle Jurassic, Kellovian), carbonate-chemogenic-the clay formation (Oxford-Kimmeridge), the sandy-carbonate-clay formation (Neocom) and the clay-sand formation (apt-Alba) also distinguish them in the northern and southern regions with their common rocks, the nature of development and the degree of research. Over the next thirty years, associated with the cessation of regular parametric, exploratory drilling, and various seismic operations.Despite the large volume of scientific, technical and other research, studies of promising deposits and territories are conducted extremely poorly.One of the important reasons for this is the interdepartmental, intersectoral variance of the work performed, the low variance of the information received. In order to increase the efficiency of the exploration and research complex of productive formations, in our opinion, the solution of the issue of oil and gas exploration and exploration in the Mesozoic of the Mangyshlak region should be carried out according to a single intersectoral, interdepartmental program with an assessment of the progress of work on further stages and final results.

Numerical Simulation and Parameter Optimization for Water-to-CO2 Flooding in a Strongly Water-Sensitive Reservoir.

Carbon dioxide flooding can accelerate the development of low-permeability reservoirs of the Kexia group in the K region of the T oil field, thus resolving the issue of inadequate water drive effects. This study was focused on the well group 80513 in the K region, and based on the reservoir and fluid parameters, a simulation model of water-sensitive post-CO2 flooding was constructed to refine the gas injection strategy gradually. The injection rate of the continuous gas injection stage was preferred based on the degree of recovery. Multiindicator and multifactor injection and extraction schemes were established to optimize and analyze the key controlling factors, including the gas injection rate, gas injection period, gas-to-water ratio, and bottom-hole flow pressure, in the carbon dioxide gas-to-water alternation process. Recovery efficiency, oil exchange rate, formation pressure, and carbon dioxide storage rate were used as indicators. After 5 years of continuous CO2 flooding, the results indicated that switching to CO2 gas-water alternating flooding was more appropriate for the target block's environment. The best development plan was achieved when the gas injection rates were 1.0 and 1.25 × 104 m3·d-1 for continuous gas injection and CO2 gas-water alternating flooding, respectively, with a gas-water ratio of 1:1, a gas injection cycle of 90 days, and a bottom-hole flow pressure of 25 MPa in the production wells. A comparison between the results revealed that the formation pressure and oil recovery efficiency of this well group significantly increased upon CO2 flooding, and the parameter optimization results were well suited for controlling the gas flurry, offering a versatile model for future development of the block.

A comparative study of the pyrolysis and hydrolysis conversion of tire

In the present study, we pyrolyzed a waste tire at various temperatures under an N2 atmosphere and a water environment in an autoclave reactor to investigate the effect of water on tire degradation. The analysis involved a comparison of product distribution, char properties, oil composition, and the behavior of heteroatom elements (especially oxygen, nitrogen, and sulfur) under different atmospheres. Elemental analysis, functional-group identification, and chemical state analysis of sulfur were performed for chars. In addition, the chemical composition, elemental composition, and molecular weight of the produced oils were evaluated. The heavy fraction of oils, not detectable by gas chromatography-mass spectrometry (GC-MS), was analyzed through Fourier-transform ion cyclotron resonance mass spectrometry (FT-ICR MS). The findings revealed that high temperatures promoted oil cracking, resulting in the formation of light oils in both pyrolysis and hydrolysis processes. Compared to pyrolysis, hydrolysis generated a higher yield of low molecular–weight oil. Elevated hydrolysis temperatures promoted aromatization, yielding an oil with a low H/C ratio and a high double bond equivalent number. Consequently, the concentration of aromatics in the light fraction of oils generated from the hydrolysis process exceeded that in oils from the pyrolysis process. Temperature exhibited a limited impact on oil composition during the pyrolysis process. Hydrolysis promoted the release of heteroatom-containing compounds at low temperatures. During pyrolysis, nitrogen was gradually released from the solid phase, whereas nitrogen-containing compounds were released early during hydrolysis, with gas-phase nitrogen accounting for more than 50 wt% at 320 °C. A maximum D-limonene yield of 45.58% was obtained at 360 °C within 0 min of hydrolysis, with the potential conversion of D-limonene into aromatics at higher hydrolysis temperatures. These results contribute to the understanding of tire valorization via hydrolysis.

Ultraviolet laser-etched Norland optical adhesive 81 micromodel for studying two-phase flow experiments

As the global energy demand grows, maximizing oil extraction from known reserves has become critical. The study of microfluidic flow and transport in porous media has become a key direction for future subsurface energy technologies. However, the high requirements of fabrication techniques and materials have constrained the progress of micro-scale experiments. In this study, we have innovatively proposed a microfluidic chip fabrication method based on ultraviolet laser, and a set of visualized microdrive platforms is developed to allow direct observation of two-phase flow processes at the pore scale. In this study, two pore structures—one with low porosity and high connectivity and the other with high porosity but low connectivity—were constructed to investigate the effect of pore structure on recovery. Two micromodels with different pore structures were fabricated, and water and surfactant drive experiments were conducted at different drive rates, respectively. The results show that increasing the replacement rate and introducing surfactant can somewhat improve the final recovery. Using surfactant is more effective in enhancing the recovery rate than increasing the replacement rate. The complexity of pore structure is one of the main factors affecting the formation of residual oil. The microfluidic experimental setup proposed in this study reduces the time and cost of conventional practical methods. It permits visualization of the oil drive process, demonstrating that the Norland Optical Adhesive 81 (NOA81) micromodel is a valuable tool in two-phase flow studies and its applications.

Study on Main Factors Controlling Development Performance of Heterogeneous Composite Flooding in Post-Polymer Flooding Reservoir

Heterogeneous composite flooding has performed well with regard to enhanced oil recovery after polymer flooding in recent years. In order to significantly increase oil recovery, the development parameters should be designed differently for each well. However, it is difficult to rapidly allocate development parameters through the lowering of computational costs. Therefore, the authors of this paper carried out research to clarify the main controlling factors of parameter allocation. Firstly, the numerical simulation domain was separated into several regions, with injection wells and production wells at the center of each region. The statistical parameters of each region were calculated. Then, the water injection rate, liquid production rate, and chemical agent concentration were allocated based on the proportion of statistical parameters in each region. A large number of development schemes were designed by combining different injection and production allocations that were calculated based on each statistical parameter. Finally, the development performance of each scheme was simulated and analyzed. The statistical parameters corresponding to the best performance scheme were regarded as the main controlling factors of heterogeneous composite flooding after polymer flooding. These results showed that the main controlling factors for the allocation of the water injection rate were pore volume and permeability variation coefficient. The main controlling factors for liquid production rate were the remaining oil saturation, formation coefficient, and reservoir pressure. The main controlling factors for chemical agent concentration were pressure and permeability variation coefficient. These findings concerning the main factors controlling development parameter allocation were validated by practical application in several well groups of an actual reservoir model. This study provides references for improving heterogeneous composite flooding performance for post-polymer flooding reservoirs in the future.

Prospects of oil and gas potential of the South Torgai sedimentary basin

One of the main directions for assessing the prospects of oil production is the study of oils. In this regard, modern geochemical studies are widely used in forecasting the oil and gas potential of the subsurface, occupying an important role in the question of the origin and source of hydrocarbons. The study is aimed at a comprehensive analysis of the geochemical characteristics of the South Torgai sedimentary basin in order to identify and assess the prospects for oil and gas potential. Comparing the composition of oils from different deposits makes it possible to determine the oil source strata, zones of oil formation and oil accumulation. The compounds in oils that are most or least susceptible to changes under the influence of factors such as water leaching, biodegradation and thermal transformation are subject to comparison. The relative content of individual classes of compounds in the oils of the Aryskum trough, the geological characteristics of oil samples and the distribution of normal alkanes are presented. In this work, a comparative analysis of previously conducted geochemical studies was carried out to determine the composition and genesis of oils in the Aryskum trough. Biomarkers in oils, which make it possible to restore the genetic properties of oils and determine the conditions of sedimentation of oil-generating organic substances, indicate the presence of suboxidation conditions, redox potential and predominantly oxidative environment in the process of sedimentation of organic substances. The results obtained are important for understanding the processes of oil formation and generation, as well as for further forecasting the oil content of the South Torgai sedimentary basin.

Assembly of spherical-shaped resistant starch nanoparticles to the oil droplet surface promotes the formation of stable oil in water Pickering emulsions

The use of starch-based nanoparticles in stabilizing Pickering emulsions has gained momentum since it offers a versatile, biocompatible, and sustainable approach with a wide range of applications. In the present study, starch nanoparticles produced using a sequential 3-step physical process were used as particle stabilizers to create Pickering emulsions. According to our results, high amylose starch nanoparticles can provide long-term colloidal stability to Pickering emulsions. The concentration of the particle-based stabilizer affected the size of the droplets, which in turn had an impact on the stability properties of the produced emulsions. By increasing nanoparticle concentration, surface and interfacial tension were reduced, providing the ability to the particles to adsorb at the interface. When starch and oil concentrations were compared using Dynamic Laser Scattering (DLS) and zeta potential, smaller droplets were produced by increasing starch amount and improved stability was depicted. Rheological profiles showed that the emulsion network structure was strengthened by the addition of nanoparticles, increasing the storage (G′) and loss (G″) moduli, as well as viscosity. In conclusion, the produced emulsions can be categorized as Pickering emulsion gels. These networks, specifically at starch nanoparticle concentration of 3% w/v and 5% w/v, have the advantage of preventing phase separation, droplet coalescence, and Ostwald ripening. The formation of a strong gel network was also obtained by Confocal Laser Microscopy (CLSM). All in all, this study provides new insights into the preparation and stabilization of starch-based Pickering emulsions, as the demand for sustainable and eco-friendly solutions in food product development is growing.

Experimental Study on Carbon Dioxide Flooding Technology in the Lunnan Oilfield, Tarim Basin

The Lunnan Oilfield in the Tarim Basin is known for its abundant oil and gas resources. However, the marine clastic reservoir in this oilfield poses challenges due to its tightness and difficulty in development using conventional water drive methods. To improve the recovery rate, this study focuses on the application of carbon dioxide flooding after a water drive. Indoor experiments were conducted on the formation fluids of the Lunnan Oil Formation, specifically investigating gas injection expansion, thin tube, long core displacement, oil and gas phase permeability, and solubility. By injecting carbon dioxide under the current formation pressure, the study explores the impact of varying amounts of carbon dioxide on crude oil extraction capacity, high-pressure physical parameters of crude oil, and phase characteristics of formation fluids. Additionally, the maximum dissolution capacity of carbon dioxide in formation water is analyzed under different formation temperatures and pressures. The research findings indicate that the crude oil extracted from the Lunnan Oilfield exhibits specific characteristics such as low viscosity, low freezing point, low-medium sulfur content, high wax content, and medium colloid asphaltene. The measured density of carbon dioxide under the conditions of the oil group is 0.74 g/cm3, which closely matches the density of crude oil. Additionally, the viscosity of carbon dioxide is 0.0681 mPa·s, making it well-suited for carbon dioxide flooding. With an increase in the amount of injected carbon dioxide, the saturation pressure and gas-oil ratio of the crude oil also increase. As the pressure rises, carbon dioxide dissolves rapidly into the crude oil, resulting in a gradual increase in the gas-oil ratio, expansion coefficient, and saturation pressure. As the displacement pressure decreases, the degree of carbon dioxide displacement initially decreases slowly, followed by a rapid decrease. Moreover, an increase in the injection rate of carbon dioxide pore volume leads to a rapid initial improvement in oil-displacement efficiency, followed by a slower increase. Simultaneously, the gas-oil ratio exhibits a slow increase initially, followed by a rapid rise. Furthermore, as the displacement pressure increases, the solubility of carbon dioxide in water demonstrates a linear increase. These research findings provide valuable theoretical data to support the use of carbon dioxide flooding techniques for enhancing oil recovery.

Using Machine Learning to Predict Oil–Mineral Aggregates Formation

The formation of oil–mineral aggregates (OMAs) is essential for understanding the behavior of oil spills in estuaries and coastal waters. We utilized statistical methods (screening design) to identify the most influential variables (seven factors in total) during OMA formation. Time was the most important factor, followed by temperature and oil/clay ratio. Moreover, machine learning was applied to predict the OMA median diameter (D50). Among the three tested algorithms, the Random Forest (RF) algorithm showed the highest accuracy, with a training R2 of 0.99 and testing R2 of 0.93. An open-source software tool that integrates the RF algorithm was developed, allowing users to easily estimate the OMA D50 based on input variables. The valuable results and the practical tool we have developed enhance the understanding and management of environmental impacts associated with oil spills.

Characteristics of Deepwater Oil and Gas Distribution along the Silk Road and Their Controlling Factors

Deepwater regions have emerged as pivotal domains for global oil and gas exploration and development, serving as strategic alternatives to conventional resources. The Silk Road region is distinguished by its abundant oil and gas reserves and stands as a leading arena for worldwide exploration and development in the oil and gas sector. Since 2012, a series of atmospheric fields have been discovered in the deep sea of the Luwuma Basin and the Tanzania Basin, with cumulative recoverable reserves reaching 4.4 × 1012 and 8.3 × 1011 m3, including multiple oil and gas fields ranking among the top ten global discoveries at that time. Profound advancements have been achieved in the exploration of deepwater oil and gas reserves along the Silk Road. However, deepwater oil and gas exploration presents challenges, such as high development costs and risks, leading to certain areas remaining underexplored and exhibiting a relatively low level of exploration activity, thereby hinting at considerable untapped potential. Deepwater sedimentary basins along the Silk Road predominantly adhere to a distribution pattern characterized as “one horizontal and one vertical”. The “horizontal” dimension refers to the deepwater basin grouping within the Neo-Tethys tectonic domain, primarily extending from east to west. Conversely, the “vertical” dimension denotes the deepwater basin grouping along the East African continental margin, predominantly extending from north to south. Recent discoveries of deepwater oil and gas reserves validate the presence of foundational elements within Silk Road basins conducive to the formation of substantial oil and gas reservoirs and the establishment of efficient migration pathways. Despite these achievements, exploration activities in deepwater oil and gas resources along the Silk Road remain relatively limited. Future exploration endeavors in deepwater regions will predominantly focus on identifying structural and lithological traps. In the deepwater areas of the Bay of Bengal, the emphasis is on lithological traps formed by Neogene turbidite sandstone deposits. In the deepwater regions of Pakistan, the focus shifts to lithological traps emerging from Neogene bio-reefs and river-channel sandstone accumulations. Along the deepwater coastline of East Africa, the focus is on lithological traps formed by nearshore Mesozoic–Cenozoic bio-reefs and seafloor turbidite sandstone formations. Within the deepwater regions of Southeast Asia, the primary objective is to locate large structural-type oil and gas fields. Analyzing the characteristics of oil and gas discoveries in deepwater areas aims to enhance the theory of the control of the formation of deepwater oil and gas, providing valuable insights for predicting future exploration directions.

Performance optimization of droplet formation and break up within a microfluidic device – Numerical and experimental evaluation

Droplet-based microfluidics, including the controlled manipulation of materials in the form of monodisperse droplets on the micrometer scale in microfluidic chips, has gained much attention due to their ability in biological assays. The capillary number of the continuous phase, as the ratio of viscous force and interfacial tension, is so important in the mechanism of droplet formation. This study aims to survey the type of continuous-phase fluid, the change in the parameters of the continuous phase, and the effect of the different flow rates ratios on the droplet formation dynamics, droplet size, distance between droplets and frequency of droplet formation. Three types of oil, including mineral, olive, and paraffin in a flow-focusing microfluidic device have been utilized numerically and experimentally. To characterize the parameters of the continuous phase affecting the droplet size, a microfluidic device has been designed to estimate of the droplet size for three different types of oil used in the assay. The results show that for a constant continuous phase velocity, the diameter of the droplets formed in olive oil has the lowest amount, followed by paraffin and mineral oil, respectively. Regarding the effects of oil type on the frequency of droplet formation and the distance between droplets, the rate of droplet formation in mineral oil, in the ratios of the variable flow rate and the constant continuous phase velocity, is the lowest and, the distance between the droplets has the highest level.

A mechanistic study of asphaltene formation and aggregation in presence of metallic-based nanoparticles

In this work, the effects of metallic-based nanostructures including iron oxide (Fe2O3), magnesium oxide (MgO) and zinc oxide (ZnO) on asphaltene precipitation and aggregation were explored. The synthesized nanoparticles were characterized by X-ray diffraction (XRD), X-ray fluorescence (XRF), Fourier-transform infrared spectroscopy (FTIR), and Brunauer, Emmett and Teller (BET) methods. Optical microscopy and asphaltene dispersant tests (ADTs) were utilized to discover the effects of nanoparticles on asphaltene stability and the size-growth of asphaltene aggregates in crude oil medium. The interactions of the asphaltene functional groups with metal oxide nanoparticles were evaluated at molecular scale by thermogravimetric analysis (TGA/DTG), FT-IR, and field emission scanning electron microscopy (FESEM). Results of different experiments exhibited that synthesized nanostructures in general postpone the asphaltene onset of precipitation (AOP) and reduce the size of asphaltene aggregates in unstable crude oil medium. MgO nanoparticles with a concentration of 300 ppm had the greatest effect on controlling the asphaltene precipitation and aggregation. The TGA/DTG analysis showed that the oxidation of pure asphaltenes occurs at a temperature of about 425 °C, while the oxidation temperature of asphaltenes adsorbed on ZnO and Fe2O3 nanoparticles occurs at around 330 °C, and for MgO nanoparticles at about 365 °C. In addition, the spectra obtained from the FT-IR analysis for asphaltenes without and with nanoparticles at the wavelengths of 1450 and 2900 cm−1 show the medium C–H stretching bonds that play the most important role in the adsorption of asphaltene on the surfaces of the nanoparticles. Also, the recorded FESEM images of the asphaltene and nanoparticles demonstrated the proper absorption of asphaltenes in the empty spaces between the structures of nanoparticles. According to the results from different experiments and intermolecular analyses, the performance of synthesized nanoparticles for retarding asphaltene precipitation and dispersing the asphaltene aggregates was in order of MgO (300 ppm) > Fe2O3 (300 ppm) > ZnO (700 ppm). The results of intermolecular analyses established the effective adsorption of the asphaltene particles onto the surface of the nanoparticles, which is caused by strong hydrogen interactions between the active sites of the asphaltene and nanoparticles. The findings of this study prove that metal-oxide nanoparticles can be utilized as an economically and environmentally-effective agents for controlling asphaltene formation and aggregation in crude oil.

Effect of different hydrophilic heads on strong interfacial activities of non-edible oil-derived ultra-long chain (UC24:1) Bio-based zwitterionic surfactants for tertiary oil recovery

One of the cross-cutting issues in green petrochemistry is discovering an efficient and sustainable technique for chemically enhanced oil recovery (EOR). Developing eco-friendly and renewable surfactants with strong interfacial activity as greener chemical materials for EOR has been a challenging topic. In this work, a new series of eco-friendly and high-performance ultra-long chain fatty acid-derived bio-based zwitterionic surfactants with different hydrophilic heads (the 2-(dimethyl(3-(tetracos-15-enamido)propyl)ammonio)acetate (TAPAA), 3-(dimethyl(3-(tetracos-15-enamido)propyl)ammonio)− 2-hydroxypropane-1-sulfonate (TAPAHPS), and 4-(dimethyl(3-(tetracos-15-enamido)propyl)ammonio)butane-1-sulfonate (TAPABS)), was developed from the non-edible fatty acid (Z)− 15-tetracosenoic acid (UC24:1) by a simple and effective method. ESI-MS, 1HNMR, and 13C NMR were used for their structural analyses. In alkali- and polymer-free systems, 0.5 g/L concentration of each surfactant could reduce the interfacial tension between Daqing crude oil and simulated formation groundwater to ultra-low value (1.971 × 10−3, 4.44 × 10−3 and 6.538 × 10−4 mN/m for TAPAA, TAPAHPS and TAPABS, respectively). These surfactants also demonstrated strong electrolyte tolerance, up to 2000 mg/L and 200 g/L of Ca2+ and NaCl, respectively. They were also structurally thermal stable up to 75 °C and biodegradable. This work consolidates our hypothesis that ultra-long chain (UC24:1) bio-based zwitterionic surfactants are of greater use than short-chain surfactants or traditional alkali-surfactant-polymer (ASP) systems for EOR applications, as they show strong interfacial activity at lower dosages in alkali- and polymer-free systems.

Improving oil and gas flowability in tight carbonates with a novel solid delayed acid

The economic development of tight carbonate reservoirs requires hydraulic or acid fracturing stimulation. Acid fracturing better activates natural fractures, resulting in increased stimulated reservoir volume and improving oil and gas flowability. In order to solve the problem of excessive acid-rock reaction due to high temperature, this paper screened four kinds of solid forms of acid with the maximum quantity of acid and reaction rate as the index and formed a high temperature-resistant mixed solid acid system with solid organic acid as the main part and inorganic solid acid as the auxiliary part. The maximum quantity of acid produced and effective acid concentration of the system were greater than 50%, and no residue was precipitated after the complete reaction. Dynamic acid-rock rate tests were performed on different types of retarded acid at 140 °C. The test results show that the solid acid dissolves to form a low-viscosity acid solution, and the reaction rate is one order of magnitude lower than that of gelled and cross-linked acids at the same hydrogen ion concentration, and it is little affected by temperature. Moreover, the paper compares the treatment effect of micro-proppants and solid acids on micro-fractures. The results show that the core permeability improvement multiples up to 900 times under low dissolution of solid acid and the formation of oil and gas flow channels with the same scale as micro-proppants. The experimental results demonstrated the ability of solid delayed acid to transport the fracture leading edge at high temperatures and effectively activate micro-fractures.

Impact of water and oleic acid on glycerol monooleate phase transition and bi-continuous structure formation in white oil.

Production of biofuels from biological feedstocks, such as soybean oil, is an important piece of the transition to renewable energy sources. Processes have been developed to co-refine these feedstocks with traditional feedstocks, however, the high concentration of polar functional groups in biofeedstocks can cause a wide range of intermediate chemical reactions and interactions. An improved understanding of the interactions of biofeedstocks and their degradation products is needed to continue to expand the usage of biofeedstocks in fuel production. In this study, the equilibrium structures of glycerol monooleate (GMO), a common intermediate product of biofeedstock processing, in white mineral oil at a wide range of compositions, temperatures, and additional byproduct concentrations (water and/or oleic acid) were characterized using small angle X-ray scattering (SAXS). It was determined that GMO can exist as crystalline aggregates in white oil or as reverse micelles depending on the concentration and temperature. The critical micelle temperature increases significantly with increasing GMO concentration but remains relatively stable with increasing water or fatty acid concentration. Fitting of the SAXS data revealed that for many compositions, the GMO formed roughly spherical reverse micelles, however, at high water concentrations (∼1 wt%), the GMO formed elongated reverse micelles. Additionally, when >1 wt% oleic acid was added to the system, bi-continuous structures were stabilized rather than discreet reverse micelles. These results help increase our understanding of the structural behavior of biofeedstock intermediate products at concentrations and temperatures relevant to biofuel production and can enable processers to design systems and products that can either leverage or prevent these interactions for improved processing performance.

Development of the Oil and Gas Potential of the Arctic Region: Issues of Methodology and Practical Implementation

In the development of methodological provisions for the integrated development of hydrocarbon resources are considered issues of improving the subsoil use of the Arctic and continental shelf of Russia. State support measures provide for the introduction of advanced technological solutions, that meet the highest environmental requirements, in all stages of the production processes of oil and gas enterprises. The application of various methodological tools to shelf projects taking into account internal specifics are justified. This contributes to formation of oil and gas centers in the Arctic region, becoming of the Northern Sea Route as a global transport route. The key areas of practical implementation of the state Arctic policy are related to the solution of infrastructure, logistics and socio-economic issues in the Arctic regions, the development of related industries. Strengthening the energy potential of the region provides the adoption of verified state and management decisions, the creation of special legal conditions for the integrated development of oil and gas fields, aimed at stimulating internal mechanisms of economic growth, preserving the unique ecosystem and biological diversity in the Arctic. To a certain extent, this is facilitated by the cluster form of development, the involvement of the largest scientific and industry institutions in the implementation of Arctic projects, which leads to improving professional competencies, and the implementation of a flexible technological policy. The complex development of hydrocarbon reserves of the Arctic and continental shelf makes a significant contribution to the achievement of technological sovereignty of the domestic economy and the advanced technological development of the oil and gas complex.

Optimization design of oil well fracturing scheme in X block of Daqing Oilfield

With the continuous development of oil fields, the remaining oil in conventional old oil fields is gradually reduced after long-term water drive development. Fracturing can change the original water drive flow channel and increase the oil production of oil Wells. After long-term water flooding development, the oil production of oil Wells in Block X of Daqing oilfield has gradually decreased, and fracturing is needed to increase production. However, Block X has three target reservoirs, and the two formations are close to each other, so stratified fracturing cannot be realized by conventional stage fracturing technology. Therefore, flow limiting method is needed to control the fracture initiation of oil formations. And each layer can be better used. The overall fracturing effect is poor, and it is necessary to carry out a separate optimization design for the control technology of fracture height. The overall fracturing sequence is: first press the third stage, then press the first stage and the second fracturing stage. There is no interference between the 19th layer and the 20th layer, and the fracturing effect is good. For the 19th small layer, the fracture half-length is about 48m, and the 20th small layer half-length is about 55m, which achieves the expected fracturing effect.

Formula system of reduce pressure and increase injection working fluid in Tamtsag oilfield

Tamtsag Oilfield is a low-permeability oilfield. In the actual production process, there will be “high water injection pressure and high injection difficulty”. In order to improve the waterflood development effect of low permeability reservoir, the selection of working fluid plays a key role. By measuring the interfacial tension between the working fluid and crude oil, combined with the depressurization and injection performance evaluation test, the anion-non-ionic surfactant working fluid system suitable for the characteristics of the Tamtsag reservoir was prepared. Under the condition that the formation water pH of oil formation in the Block 21 of Tamtsag oilfield is 7.5 and the salinity is 3000 mg/L, the injection increasing formula selected in this paper is: 0.9 % coconut oil diethanolamide+0.7 % sodium dodecylbenzene sulfonate+0.5 % anhydrous ethanol+3 % clay stabilizer. For cores with permeability lower than 80 mD, the depressurization rate can reach more than 25 %; For cores with permeability less than 15.9 mD, the depressurization rate can reach more than 30 %. The working fluid system can effectively improve the effect of increasing injection in Tamtsag Oilfield.

Evaluating Hydrocarbon Prospects and Petrophysical Properties in Sepinggan Formation, East Kalimantan's Lower Kutai Basin

This study aims to determine hydrocarbon zones and analyze petrophysics in the Sepinggan Formation, located in the lower Kutai Basin, which is one of the oil and gas producing formations in Indonesia. The data used includes 5 well log data and mudlog data. The results of the study show that the Sepinggan Formation has 14 potential zones dominated by carbonate sandstone lithology with a slight mixture of coal. Some key findings in the petrophysical analysis include the largest average shale volume of about 41% in zone 1 of well SPG-V8, the largest average porosity of about 24% in zones 1 and 2 of well SPG-V1, the largest average permeability of about 2591.08 mD in zone 1 of well SPG-V2, and the largest average water saturation of about 56% in zone 2 of well SPG-V7. Based on these results, further evaluation of hydrocarbon potential in the identified potential zones and optimization of exploration and exploitation techniques are needed to improve the efficiency of oil and gas production in the Sepinggan Formation.

Study on reservoir characteristics of Chang2 reservoir in southwest Ordos Basin

In order to clarify the reservoir characteristics of the Chang2 oil formation in the GQ block of the Ordos Basin, the reservoir characteristics and pore structure of the Long 2 oil formation in the study area were investigated using experimental data such as cast thin section, scanning electron microscope (SEM) and mercury pressure curve. The results show that the Chang2 oil formation in the study area mainly develops medium sandy fine-grained feldspathic sandstone, and the pore types are rock dissolution pores and intergranular pores. The reservoirs of the Chang2 oil formation group in the study area were evaluated and classified by applying piezomercury curve banding, and the reservoirs were classified into three categories: Small pore-medium fine-throat type-medium pore-medium fine-throat type, Fine pore-micro-throat type and Mesoporous-coarse throat type. In the study area, most of the reservoirs in Chang2 are Small pore-medium fine-throat type-medium pore-medium fine-throat type, accounting for 50% of the total, while Mesoporous-coarse throat type accounts for 34.7% and Fine pore-micro-throat accounts for 15.3% of the total. The Chang2 oil reservoir in the study area is mainly developed as a general reservoir.