Efficiency Of Oil Production Research Articles

A Novel Analytical Solution of Radial Diffusion Equation with Constant Terminal Rate of Slightly Compressible Fluid

In reservoir engineering, the flow and type of fluids crossing porous media, are associated with pressure drops leading to variations on hydrodynamic parameters and the filtration stages which are of interest to be assessed as they impact the production efficiency of oil and gas industry. These parameters are the key to the practical solutions of numerous subjects faced during oil field exploitation. Dealing with the problem of sound field development initiatives requires a rigorous examination of unsteady filtration of slightly compressible fluid in the reserves layer. The state of the art of the proposed scientific work is to present an innovative mathematical approach that gives unique results, in the mathematical connection and combination of the equations used versus existing diffusion equation in the case of the constant terminal rate solution. This model helps the designers in the field of oil and gas to better and faster evaluate the diffusivity of the pay zones, the different hydrodynamic parameters, and the different variables that take part in the development of fluid filtration processes in the porous medium expressed as in the dependence of time, distance, and other variables, all of which together impact the well testing and long-term projections.

Exploring the Application of Large Language Models Based AI Agents in Leakage Detection of Natural Gas Valve Chambers

Leakage problems occur from time to time due to the large number of equipment and complex processes during oil and gas production and transportation. The traditional detection methods highly depend on manpower with large workload and are prone to missed and false alarms, which seriously affects the efficiency and safety of oil and gas production and transportation. With the continuous improvement of information technology and the rapid advancement of artificial intelligence (AI), the research on leakage detection technology based on AI methods has attracted more and more attention. This paper discusses the application scenarios of an AI agent based on the recently emerged large language model (LLM) technology in oil and gas production leakage detection: (1) Compared with the traditional leakage detection methods, this paper innovatively employs a combination of AI-based diagnostics and infrared temperature measurement technologies to develop a specialized small model for oil and gas leakage detection, which has been proven to significantly improve the accuracy of detecting industrial venting events in natural gas valve chambers; (2) By employing retrieval-augmented generation (RAG) technology, a knowledge vector library is constructed, utilizing a series of leakage-related documents, assisting the LLM to carry out knowledge questioning and inference. Compared with the traditional SimBERT, the accuracy can be improved by about 15% in the Q&A search ability test. The correct rate is about 70% higher than the SimBERT in the Chinese complex reasoning quiz. Also, it can still remain stable under high load conditions, with the interruption rate of retrieval closing to zero. (3) By combining the specialized small model and the knowledge Q&A tool, the natural gas valve chambers’ leakage detection AI agent based on the open-source LLM model was designed and developed, which preliminarily achieved the leakage detection based on the specialized small model, and the automatic processing of the retrieval reasoning process based on the knowledge Q&A tool and the intelligent generation of corresponding leakage disposal scheme. The effectiveness of the method has been verified by actual project data. This article conducts preliminary explorations into the in-depth applications of AI agents based on LLMs in the oil and gas energy industry, demonstrating certain positive outcomes.

ESTIMATION OF THE CLEANING TIME OF THE BOTTOM-HOLE ZONE OF WELLS IN CONDITIONS OF UNCERTAINTY

The aim of the work is to analyze changes in the maximum optimal flow rates of wells operating various groups of productive formations of the Volga-Ural oil and gas province under conditions of uncertainty of geological and field data. The relevance of the work is due to the deterioration of the structure of residual oil reserves and the need for the most efficient extraction of liquid hydrocarbon resources, optimization of design methods for various treatments of the bottomhole formation zone. Using geological and statistical modeling systems, the timing of cleaning the bottomhole zones of wells from drilling products was determined at the time they reached their maximum optimal flow rate in conditions of deposits confined to various stratigraphic horizons, and appropriate models of changes in productivity coefficients were constructed. The factors influencing the recovery time of the real properties of the reservoir at the point of opening it by the well, which, among other things, determines the profitability of the process of selecting residual oil reserves, have been established. Among them, the most relevant and necessary for the implementation of an integrated approach to computer support procedures for the development of oil fields are the productivity of wells, fracturing of formations, their proximity to a particular tectonic-stratigraphic complex, geological, physical and physico-chemical properties of formations and their saturating fluids. For the deposits of the Famensk tier of deposits of the Volga-Ural oil and gas province, a multiple decrease in the time of removal of reaction products after hydrochloric acid exposure at objects with low fracturing has been established. At the same time, additional processing of the bottomhole formation zone within areas with high drilling density does not affect the total cleaning time of the bottomhole zone of wells. Stimulation of the removal of drilling mud filtrate and additional products of formation reactions by injection of hydrochloric acid compositions under certain conditions can lead to a decrease in the actual productivity of wells due to the introduction of less developed and dead-end cracks into the drainage process. The existence of the specifics of the procedure for cleaning the bottomhole formation zone depending on the geological and physical parameters of productive formations is substantiated and various patterns of changes in the productivity coefficient depending on the time of wells reaching the maximum optimal flow rate are revealed. The results obtained make it possible to make informed technological decisions to improve the efficiency of oil production, including in conditions of uncertainty, which may be caused by the lack of the necessary volume of hydrodynamic studies of wells.

Comparative Study on Artificial Fracture Modeling Schemes in Tight Reservoirs—For Enhancing the Production Efficiency of Tight Oil and Gas

In order to improve the reliability of the deployment of production schemes after artificial fracturing in tight reservoirs, it is urgent to carry out research on the description of fractures after artificial fracturing. In this study, taking the Chang 61 oil formation group in the Wangyao South area of Ordos Basin as an example, three different fracture modeling schemes are used to establish the geological model of fractured reservoirs, and the fitting ratios of the respective reservoir models are calculated by using the method of reservoir numerical simulation of the initial fitting, and the optimal fractured reservoir modeling scheme is screened in the end. The research area adopts three types of fracture prediction results based on FMI fracture interpretation data, seismic fracture prediction data, and rock mechanics artificial fracturing simulation data. On this basis, geological models of fractured reservoirs are established, respectively. The initial fitting of reservoir values of each geological model are compared, and the highest initial fitting rate of reservoir values is 88.44%, which is based on rock mechanics artificial fracturing simulation data. However, the initial fitting rate of the reservoir model was the lowest at 75.76%, which was established based on the fracture random modeling results of FMl fracture interpretation data. Under the constraints of seismic geostress prediction results and microseismic monitoring data, the simulation results of rock mechanics artificial fracturing fracture are used as the basis, on which the geological model of artificially fractured reservoirs is thus established, and this scheme can more realistically characterize the characteristics of fractured reservoirs after artificial fracturing in the study area.

Применение новых технологий кислотной обработки пластов для восстановления продуктивности пласта

Oil recovery, measured by the oil recovery factor (ORF), is a key indicator of the efficiency of oil production. In Russia, the ORF decreased to 0.3 while in the United States this indicator increased to 0.4. About 90% of Russian oil is produced by large holdings, the structure of reserves is shifting towards hard-to-recover, which requires the use of new methods to increase oil recovery. Primary and secondary production allows only 20-50% of oil to be extracted, what makes the use of tertiary methods necessary. The development of horizontal wells with multistage hydraulic fracturing contributes to the development of new field sites, but requires careful preparation of wells to minimize risks and cost increases. Cleaning the bottomhole area using acidic formulations is often the only cost-effective way to restore the productivity of a horizontal well. The improved method of acid composition reduction using a guar gel with delayed “crosslinking”, which ensures uniform treatment of all productive zones of the formation is considered in article. The technology allows for continuous multi-stage acid treatment, temporarily blocking highly permeable areas and increasing the coverage of acidic effects on poorly drained areas. The calculation of the diverter volume considers the average efficiency of the liquid after mini-fracturing, adjusting the volume depending on the efficiency of the liquid at each port.

Mobility and Method of Enhanced Oil Recovery for Yingxiongling Shale Oil

Abstract There are abundant shale oil resources in Yingxiong Ling, Qaidam Basin, but the oil recovery rate is low due to complex lithofacies types, large physical property differences, diverse pore types and structures, and strong heterogeneity. In order to improve the oil recovery efficiency of Yingxiong Ling shale oil, based on the analysis of the factors affecting the micro-mobility of Yingxiong Ling shale oil, through spontaneous imbibition and nuclear magnetic test, the oil mobility evaluation of different lithology reservoirs and different pore structures and the feasibility of surfactant to improve oil recovery were carried out. The research results show that: (1) Yingxiong Ling shale oil has considerable mobile hydrocarbon base, effective seepage channels, high viscosity reduction conditions and elastic properties, and has the potential for efficient development. (2) In the spontaneous imbibition state, the utilization efficiency of laminar limestone and laminar limestone are 10% and 12.5%, respectively, and that of small pores, large pores and texture cracks are 6.7%, 5.2% and 1.8%, respectively. The overall utilization efficiency is low. (3) The solution containing surfactant components can effectively improve the crude oil production degree of Gan Chaigou shale oil reservoir. The variable-viscosity fracturing fluid can increase the oil production efficiency to 21.46%, and the nano-emulsion can increase the oil production efficiency to 33.43%. The surfactant has a significant effect on the EOR of Yingxiong Ling shale oil. Based on the analysis of micromobility, the characteristics of crude oil mobility and the experimental results of enhanced oil recovery by surfactants, it is concluded that the oil recovery of Yingxiong Ling shale oil can be greatly improved by combining high efficiency surfactants with large-scale volumetric fracturing.

Preparation and Evaluation of Physical and Chemical Properties of Resin Plugging System Suitable for Formation Plugging of Malignant Lost Circulation.

Lost circulation is one of the important problems that restricts the speed and efficiency of oil and gas drilling and production. In this study, a resin plugging system was successfully developed for lost circulation formation. The resin plugging system showed excellent performance under high temperature and pressure conditions. The experimental results showed that the compressive strength of the resin plugging material can reach 9.23 MPa after curing, which is significantly higher than that of the traditional polymer gel material. The resin material can achieve effective curing in the temperature range of 60 °C to 100 °C, and the curing time decreases with the increase of temperature and only needs 3.46 h at 140 °C. The microstructure results showed that the resin material can form a chain or three-dimensional network structure after curing, which can effectively increase the toughness and strength of the cured plugging layer. Infrared and thermogravimetric analysis further confirmed the thermal stability of the chemical bonds in the material, and the initial decomposition temperature was about 241 °C, indicating that it had good thermal stability at about 300 °C. In addition, the effects of curing temperature, salinity, and drilling fluid pollution on the properties of the resin plugging agent were also investigated. The results showed that curing agent dosage and curing temperature are the key factors affecting curing time, while salinity and drilling fluid pollution affect the curing strength and overall properties of the materials. After adding 20% KCl polysulfonate drilling fluid, the compressive strength of the consolidated body decreased to 4.55 MPa. This study can provide an efficient and reliable plugging solution for malignant loss formation.

Advancing Oil Production Efficiency with Next-Generation Nano emulsion Capsules: Harnessing Doped MgZnO2 for Superior Inhibition of Calcite Scale Formation

Abstract This work presents doped MgZnO2 nano emulsion capsules as a novel approach for reducing calcite scale formation in oil production. The nano emulsion capsules are synthesized via ultrasonication and precipitation methods, with morphology and size distribution analysed by scanning electron microscopy (SEM), transmission electron microscope [TEM] and dynamic light scattering (DLS).` with an average particle size of 50 nm. Static scale inhibition tests showed over 90% inhibition efficiency at a Nano emulsion concentration of 100 mg/L. Rigorous static and dynamic scale inhibition testing precipitation and showcases remarkable efficiency exceeding 80% in preventing calcite deposition under simulated conditions. Gravimetric validates cation and online pressure monitoring validate superior performance compared to conventional inhibitors, with up to 30% enhancement in mitigation. The controlled release properties of the Nano emulsion capsule allow for persistent scale inhibition even after 72 hours of continuous operation. Furthermore, ecotoxicity evaluations through bioassays affirm the eco-friendly characteristics of the Nano emulsion technology. As a whole, this research shows how highly promising doped MgZnO2 Nano emulsion capsules are as a long-term, high-performing solution to scale-related problems in the oil sector.

Methods of increasing the efficiency of energy supply to oil and gas industry enterprises

Realization of high-tech designs in gas and oil industry contributes to more efficient functioning of production. Development of quality minerals is not a scientific and technical progress, but a stable level indicator based on the general economic aspect.Therefore, the introduction of high quality updated technologies and additions to production functioning systems always leads to a greater need for their use. To maximize energy efficiency in gas and oil production, it is recommended to use high-quality autonomous power sources. The sets of optimization possibilities on algorithms of systems of distribution of power loads of electric transformer substations taking into account large productivity of producing wells at oil fields are developed. Recommendations on quality utilization, developed on the basis of long algorithms, allow to increase step-by-step nominal level of power loads at pumping units operation. It is proved that to maximize energy efficiency enterprises need to use their own high-quality autonomous power sources. The article considers the efficiency and cost-effective possibilities of production energyconsuming and quality functioning equipment in the oil and gas industry. In addition, taking into account the benefits on the basis of the study was carried out a largescale analysis of data on the characteristics of relative efficiency and reliability to the technical condition of gas turbine and gas piston power plants.

Strategy for increasing the productivity of low-permeability reservoirs at the U-XIV horizon of the field in the Mangystau region

This article discusses the actual problems of developing residual reserves in mature fields with The article analyzes modern problems of development of residual oil reserves in mature fields with low reservoir properties. The field under study is characterized by multiple productive formations, tectonic disturbances and a variety of lithological characteristics in the intervals of the Jurassic productive strata. The field is characterized by structural complexity, heterogeneity of productive strata, various degrees of reserves development and a variety of residual balance reserves. The purpose of the work was to identify areas with low reservoir properties and assess the possibilities of optimizing their exploitation to improve the efficiency of oil production. To analyze current and predicted oil recovery factors (ORF), a calculation tool was developed using methods for evaluating displacement characteristics, including the Sazonov, Kambarov, Pirverdyan, Sipachev, Nazarov, Abyzbayev and Gaisin methods. These methods take into account various dependencies of the development parameters, which allows for more accurate prediction of oil recovery factors in the studied areas. The work also includes ranking of areas by residual recoverable reserves, production rates and projected growth of the oil recovery factor. Promising areas were identified for the construction of sector geological and hydrodynamic models (GHDMs), which allows for a more detailed assessment of opportunities to improve development efficiency. GHDMs were built and adapted for two selected areas with low reservoir properties, taking into account well parameters, development history, and reservoir filtration characteristics.

Study of tertiary methods for enhancing oil recovery in carbonate reservoir fields

Background: The dynamic development of the oil and gas industry is of key importance for the economy of Kazakhstan. The country's long-term strategy for the development of the oil and gas complex is aimed at increasing oil and gas production. However, every year oil companies are faced with a decrease in easily accessible reserves, which forces them to develop hard-to-recover reserves, including fracture-pore-type reservoirs of carbonate deposits. In Kazakhstan, there are many fields with fractured porous reservoirs that are at a late stage of development, which requires their detailed study to improve oil recovery. Aim: The purpose of this work is the scientific substantiation of new technological approaches, aimed at increasing the final oil recovery factor, based on research and analysis of the world experience in oil production from fractured porous carbonate reservoirs. Materials and methods: As part of this study, the works have been carried out to model the injection of various agents, in particular gas and water, into the carbonate formations, which includes the creation of detailed geological and hydrodynamic models, taking into account the features of the fractured pore structure of carbonate formations, and simulations for various scenarios for the injection of agents with the use of the ECLIPSE™ software product (Schlumberger). Gas has been injected into different parts of the reservoir to assess the impact on the efficiency of oil displacement. Results: A study of the field, using a sector model, has shown that the greatest production volumes are achieved when perforating the upper part of the formation. In this case, there is a mixing of the flow of injected gas and oil, which significantly increases the efficiency of oil production. Options with perforation into the middle and lower parts of the formation demonstrate less efficient piston gas displacement. Experimental modeling of water injection into a carbonate reservoir has revealed that water injection leads to uneven fluid movement due to a developed fracture system. An analysis of the tracer studies has confirmed that the injection well has a significant impact on the formation of a stable water cut channel, especially in the southern part of the facility, which leads to an increase in the water cut of the produced product. Conclusion: The modeling has shown that gas injection with the perforation of the upper part of the formation provides the greatest hydrocarbon production. Optimizing the perforation interval is an important factor for increasing production in the future development strategies. The water injection experiment has revealed that a developed system of fractures in carbonate reservoirs leads to uneven fluid movement, increasing the water cut of the produced product. The use of the flow diversion technologies can reduce this effect and increase production efficiency. Different stimulation techniques for the carbonate reservoirs show significant differences in oil recovery factors, highlighting the importance of modeling for optimizing the production processes.

Increasing productivity by using smart gas for optimal management of the gas lift process in a cluster of wells

In the face of the escalating global energy demand, the challenge lies in enhancing the extraction of oil from low-pressure underground reservoirs. The conventional artificial gas lift method is constrained by the limited availability of high-pressure gas for injection, which is essential for reducing hydrostatic bottom hole pressure and facilitating fluid transfer to the surface. This study proposes a novel ‘smart gas’ concept, which involves injecting a gas mixture with an optimized fraction of CO2 and N2 into each well. The research introduces a dual optimization strategy that not only determines the optimal gas composition but also allocates the limited available gas among wells to achieve multiple objectives. An extensive optimization process was conducted to identify the optimal gas injection rate for each well, considering the limited gas supply. The study examined the impact of reducing available gas from 20 to 10 MMSCFD and the implications of water production restrictions on oil recovery. The introduction of smart gas resulted in a 3.1% increase in overall oil production compared to using natural gas. The optimization of smart gas allocation proved effective in mitigating the decline in oil production, with a 25% reduction in gas supply leading to only a 10% decrease in oil output, and a 33% reduction resulting in a 26.8% decrease. The study demonstrates that the smart gas approach can significantly enhance oil production efficiency in low-pressure reservoirs, even with a substantial reduction in gas supply. It also shows that imposing water production limits has a minimal impact on oil production, highlighting the potential of smart gas in achieving environmentally sustainable oil extraction. Furthermore, the implementation of the smart gas approach aligns with global environmental goals by potentially reducing greenhouse gas emissions, thereby contributing to the broader objective of environmental sustainability in the energy sector.

Diagnostics of velocity-flow characteristics in laminar flows

Understanding and evaluating various types of fluid movement is important for the analysis and design of systems and devices related to hydraulics and hydrodynamics, including hydrocarbon production and transport systems. Knowledge of stationary and non-stationary types of motion makes it possible to predict and control the behavior of a fluid under various conditions. The article discussed the issues of diagnosing stationary and non-stationary and gravitational flows. It has been established that the time of transition to a stationary mode in pipelines mainly depends on the geometric parameters of the pipeline and the rheological properties of the pumped systems. It is known that many issues related to the management of technological processes and the improvement of efficiency in oil and gas production are closely associated with the movement of homogeneous and heterogeneous fluids with various rheological and physico-chemical properties in pipelines during extraction, collection, and transportation, which have different forms and hydraulic characteristics. In the laminar flow regime, a methodology has been developed to determine the transition time to a steady-state operation mode, based on the flow characteristics of viscous and visco-plastic fluids, taking into account inertia forces. It has been determined that, unlike viscous fluids, the time to reach a steady-state operation mode for visco-plastic flows also varies depending on the formation of the flow core, which is determined by the initial yield stress. In the article, a mathematical expression is provided for determining the flow rate for visco-plastic fluids in laminar flow, taking into account the pressure losses due to inertia forces for viscous fluids. The results obtained are explained to eliminate the difference and increase accuracy when determining the flow rate using the Poiseuille formula for visco-plastic laminar flows.

Advances in well design and integrity: Areview of technological innovations and adaptive strategies for global oil recovery

Advances in well design and integrity are critical for enhancing global oil recovery rates. This review reviews technological innovations and adaptive strategies that drive efficiency and sustainability in oil production. The review discusses key themes such as reservoir characterization, wellbore stability, drilling fluids, and completion techniques. It highlights how these factors impact well integrity and production rates. The review emphasizes the importance of integrating innovative technologies and adaptive strategies to overcome challenges in complex reservoir environments. Key findings include the importance of reservoir characterization in designing wells that optimize recovery rates. It also highlights the role of wellbore stability in ensuring long-term integrity and reducing risks associated with drilling operations. The review discusses the advancements in drilling fluids, including the use of nanotechnology and biodegradable materials, to improve wellbore stability and minimize environmental impact. Additionally, the abstract explores advances in completion techniques, such as intelligent completions and sand control systems, to enhance production efficiency and reservoir management. It also discusses the integration of digital technologies, such as data analytics and artificial intelligence, to optimize well performance and reduce operational costs. The review concludes by highlighting the need for continued research and development to address the evolving challenges in global oil recovery. It emphasizes the importance of collaboration between industry stakeholders, research institutions, and regulatory bodies to drive innovation and ensure sustainable practices in oil production. Overall, the abstract provides a comprehensive overview of the technological innovations and adaptive strategies that are shaping the future of well design and integrity in the global oil industry. his review covers the evolution of well design practices, the application of new materials and technologies, and the strategic adaptations required to maintain operational safety and efficiency in diverse environmental conditions.

Assessment of heavy oil recovery mechanisms using in-situ synthesized CeO2 nanoparticles

This project investigated the impact of low-temperature, in-situ synthesis of cerium oxide (CeO2) nanoparticles on various aspects of oil recovery mechanisms, including changes in oil viscosity, alterations in reservoir rock wettability, and the resulting oil recovery factor. The nanoparticles were synthesized using a microemulsion procedure and subjected to various characterization analyses. Subsequently, these synthesized nanoparticles were prepared and injected into a glass micromodel, both in-situ and ex-situ, to evaluate their effectiveness. The study also examined the movement of the injected fluid within the porous media. The results revealed that the synthesized CeO2 nanoparticles exhibited a remarkable capability at low temperatures to reduce crude oil viscosity by 28% and to lighten the oil. Furthermore, the addition of CeO2 nanoparticles to the base fluid (water) led to a shift in the wettability of the porous medium, resulting in a significant reduction in the oil drop angle from 140° to 20°. Even a minimal presence of CeO2 nanoparticles (0.1 wt%) in water increased the oil production factor from 29 to 42%. This enhancement became even more pronounced at a concentration of 0.5 wt%, where the oil production factor reached 56%. Finally, it was found that the in-situ injection, involving the direct synthesis of CeO2 nanoparticles within the reservoir using precursor salts solution and reservoir energy, led to an 11% enhancement in oil production efficiency compared to the ex-situ injection scenario, where the nanofluid is prepared outside the reservoir and then injected into it.

Synergizing Solar Power with Enhanced Oil Recovery: Integrating Solar-Assisted Methods into Existing EOR Techniques

This study investigates the utilization of solar energy to enhance the efficiency of oil recovery processes, known as Solar Assist-Enhanced Oil Recovery (SA-EOR). The project objectives involve assessing the feasibility and effectiveness of integrating solar technologies with traditional oil recovery methods, such as steam injection or water flooding, to improve oil production rates and reduce operational costs. Methods employed include computational modeling, laboratory experiments, and field trials to evaluate various solar-assisted techniques and their impact on oil recovery. Key findings suggest that solar integration can enhance oil recovery by optimizing thermal processes, improving fluid mobility, and reducing environmental footprint. Additionally, the study underscores the economic viability and sustainability of SA-EOR solutions in the context of evolving energy landscapes. Overall, this research contributes valuable insights into the potential of solar technologies to revolutionize conventional oil recovery practices and advance towards more efficient and environmentally friendly energy production methods. Methods, termed Solar Assist-Enhanced Oil Recovery (SA-EOR). The objective is to investigate the efficacy of utilizing solar power to optimize thermal processes in oil extraction, such as steam injection or water flooding. Through computational modeling, laboratory experiments, and field trials, various SA-EOR techniques are evaluated for their potential to enhance oil recovery rates and reduce environmental impact. Findings indicate promising opportunities for leveraging solar energy to improve fluid mobility, optimize reservoir conditions, and ultimately increase oil production efficiency. This research underscores the significance of SA-EOR methods in advancing sustainable energy practices within the oil industry while addressing pressing environmental concerns.

Asphaltene Adsorption on Solid Surfaces Investigated Using Quartz Crystal Microbalance with Dissipation under Flow Conditions.

Asphaltenes can cause operational challenges in petroleum production facilities and adversely affect production by adsorption on mineral surfaces and alteration of the oil wettability of reservoirs. Therefore, understanding asphaltene adsorption mechanisms and their effects is crucial to improving the efficiency of oil production and reducing costs. In this study, we focus on understanding the impact of asphaltene concentration and the depositing environment of asphaltene adsorption on solid surfaces using the quartz crystal microbalance with dissipation (QCM-D) technique. The initial and long-term kinetics of adsorption at different concentrations were examined on three different solid surfaces including silicon dioxide to represent quartz mineral, stainless steel, and gold. The frequency-dissipation data showed evidence of monolayer adsorption initially, followed by multilayer formation. At short times, the adsorbed mass increased linearly with time, suggesting that the process was kinetically controlled rather than diffusion-controlled. The results were reproducible and did not depend on convection velocity but did depend on the surface material. At later stages, the monolayer development appeared to follow the random sequential adsorption (RSA) theory. Once multilayer adsorption commenced, the rates agreed well with the two-layer model of Zhu and Gu, 1990. The impact of asphaltene adsorption on the wettability of the surface was examined using contact angle studies, which showed decreasing water wettability with an increase in the adsorbed mass. The contact angle of water after 12 h of adsorption leveled off at around 100° on all three surfaces. Contact angle measurements were also used to evaluate if brine salinity causes the wettability alteration of surfaces with the adsorbed asphaltene. The results indicate that at 3% NaCl solution, the contact angle decreased only slightly by less than 2°.

The use of branched horizontal wells at the Zhanazhol field to increase oil recovery

The research presents an analysis and experiment on horizontal wells of the Zhanazhol field, an analysis of the operation of horizontal wells is carried out. The analysis of the factors affecting the efficiency of oil production by horizontal wells is carried out, experimental and industrial methods of operation are proposed for further implementation of horizontal well technology. The design of the construction of branched horizontal wells has been carried out. The purpose of this work is to substantiate the feasibility of switching to fundamentally new development systems using horizontal wells to increase the flow rate of liquid hydrocarbons using the example of the Zhanazhol field. The results of pilot tests of drilling branched horizontal wells to increase oil recovery at the Zhanazhol field are summarized. At the Zhanazhol field, the maximum capacity of oil reservoirs reaches about 190 m. The average capacity of oil–saturated reservoirs is about 3 m. There are intervals of impermeable interlayers in the productive formation. The thickness of most impermeable layers varies within 5 m. An impenetrable layer with a thickness of about 10 m is spreading widely. This affects the nutrition and energy supplementation of oil reservoirs, resulting in a rapid decrease in oil production and reservoir pressure. For example, the average daily flow rate of oil with a 15 mm fitting is more than 150 tons, but the current flow rate of oil with a 7 mm fitting is 52 tons (horizontal well No. 2407). The technology of drilling branched horizontal wells in certain geological conditions allows: to obtain initial flow rates 10 times higher than the flow rates of conventional wells with an increase in the cost of drilling only 1.5 - 2 times; to ensure accumulated production over 10-15 years of operation 10 times higher at the cost of extracted oil 3-5 times lower than for neighboring conventional wells; to increase the total oil recovery from productive formations by 20-30 percent; to thin the well development grids.

Application of digital technologies in the management of oil well pumping systems in oil extraction

In recent years, one of the trends in oil well production has been the continuous growth of interest in intelligent monitoring and control systems for mechanized well assets. This is attributed, on one hand, to the increasing number of oil fields worldwide reaching maturity and the development of new challenging reservoirs (in terms of viscosity, water cut, and sand production). On the other hand, it is driven by the necessity to enhance the economic efficiency of oil production, including cost reduction and minimizing losses. The emergence of «smart» oil production technologies, such as programmable drives for well pumps, also contributes significantly to addressing these issues. Their application allows for increased reliability and lifespan of pump equipment, reduced well downtime and failures, prevention of negative scenarios during oil production, and facilitates the visualization of parameters in a user-friendly manner. Despite the widespread use of digital technologies in the oil and gas industry, there is still significant potential for further digitization to expand operations for enhanced safety and productivity. This article presents the experience of creating and testing such a control station for screw pump units at an oil field.

Numerical simulation of CO2-enhanced oil recovery in fractured shale reservoirs using discontinuous and continuous Galerkin finite element methods

Introduction: This study explores the potential of enhancing shale oil recovery and reducing CO2 emissions through CO2 injection in fractured shale reservoirs. The importance of this approach lies in its dual benefit: improving oil extraction efficiency and addressing environmental concerns associated with CO2 emissions.Method: We employed a discrete fracture-matrix model to simulate CO2 flooding in fractured shale reservoirs, utilizing both discontinuous Galerkin (DG) and continuous Galerkin (CG) finite element methods. The DG-CG FEM’s accuracy was validated against the McWhorter problem, ensuring the reliability of the simulation results. Our model also considered various factors, including reservoir heterogeneity, fracture permeability, CO2 injection volume, and gas injection patterns, to analyze their impact on shale oil recovery.Result: Our simulations revealed that fractured reservoirs significantly enhance shale oil production efficiency compared to homogeneous reservoirs, with an approximate 48.9% increase in production. A notable increase in shale oil production, by 15.8%, was observed when fracture permeability was increased by two orders of magnitude. Additionally, a fourfold increase in CO2 injection rate resulted in a 31.5% rise in shale oil production. Implementing a step-by-step reduction in injection volume while maintaining the total CO2 injection constant proved to be more effective than constant-rate injections.Discussion: The study demonstrates the effectiveness of CO2 flooding in fractured shale reservoirs for enhancing shale oil recovery.