The study aims to improve the efficiency of oil field development at the Kalamkas field through the implementation of new methods for analyzing hydrodynamic survey data and monitoring well conditions. It is hypothesized that the use of integrated geophysical and hydrodynamic methods will enhance forecasting accuracy, optimize field operations, and increase the hydrocarbon recovery factor. An integrated approach combining pulsed neutron logging (PNL), acoustic cementometry (AC), inflow and injectivity profile evaluation methods, and specialized software for advanced data interpretation was applied, significantly improving the accuracy of well condition analysis. The analysis enabled the identification of oil and gas saturation intervals, zones of increased water cut, and cementing defects in casing, and allowed for a quantitative assessment of reservoir permeability dynamics. Hydraulic fracturing application resulted in a 10–15% increase in permeability in certain zones, with an average oil recovery factor increase of 5%. Analysis of PNL data demonstrated the transition of oil-saturated reservoirs to water saturation during development, confirmed by geophysical and pressure build-up survey results. The study identified the primary causes of increased water cut and key factors leading to production rate decline. Proposed measures for optimizing operating modes and well grid efficiency contribute to improving existing field management practices.

In this article, composite binders based on industrial waste—phosphogypsum, granular phosphoric slag, and burnt barium carbonate tailings––are investigated. It was found that the optimal composition (65% slag, 20% phosphogypsum, 15% tailings) provides compressive strength up to 31.1 MPa after steaming, which corresponds to grade M300 cement. Replacing natural gypsum with phosphogypsum increases strength by 5–10%, and using waste reduces cost by 20–25% compared to traditional binders. This technology eliminates the need for high-temperature firing, reducing energy consumption by 40–50%. Neutralization of harmful impurities of phosphogypsum with oxides of MgO and CaO reduces the ecotoxicity of the material by 70–80%. It is shown that hydrothermal treatment accelerates hardening, providing 90% of brand strength in 28 days. The developed binders are promising for the production of building blocks, road surfaces, and land reclamation.

Cellulose-based materials have been widely investigated as sustainable sorbents for oil spill remediation due to their renewability, biodegradability, low density, and structural diversity. However, reported performance varies substantially across material classes, modification strategies, and testing conditions, making direct comparison difficult. This review summarizes recent progress in cellulose-based sorbents for oil removal, with emphasis on the relationships between processing methods, pore architecture, surface wettability, and sorption behavior. Native cellulose materials, chemically modified cellulose, aerogels, nanocellulose-based systems, and carbonized cellulose are comparatively discussed in terms of oil uptake, selectivity, sorption kinetics, retention stability, reusability, and mechanical performance. The analysis indicates that sorption efficiency is controlled by the combined effects of hierarchical porosity, surface characteristics, and structural integrity. Native materials provide low cost and rapid uptake but limited selectivity, whereas chemically modified systems show improved hydrophobicity and oil retention. Aerogels generally exhibit some of the highest reported absorption capacities but often suffer from low mechanical durability. Nanocellulose-based materials generally offer a balanced combination of sorption capacity and stability, while carbonized materials typically provide enhanced retention at the expense of transport rate. Current limitations, including scalability, durability, and realistic operating conditions, are also discussed to outline future directions for the design of efficient cellulose-based oil sorbents.

The rheological properties of drilling fluids, such as plastic viscosity, yield point, and gel strength, are critical for ensuring efficient and safe oil and gas well drilling. Traditional methods for rheological analysis, reliant on manual or semi-automated viscometers, suffer from delays and inability to provide continuous data, increasing operational risks. This study presents the development and validation of an automated software-hardware complex designed for real-time monitoring of drilling fluid rheology. The system integrates inline rheometers, pressure and temperature sensors, and advanced data processing algorithms to deliver accurate measurements with a response time of 0.8 seconds. Laboratory tests demonstrated errors of ±4.2% for viscosity and ±7.8% for yield point compared to the Fann 35 viscometer, while field tests under simulated drilling conditions (30–100°C, 5–20 MPa) confirmed reliability with errors below ±9.2%. Case studies showcased rapid detection of anomalies, enabling proactive fluid management. The complex offers a scalable, integrated solution, reducing non-productive time and enhancing well stability. Recommendations include machine learning integration for predictive analytics and cloud-based analytics for remote monitoring, with future work targeting extreme conditions and other fluid types. This advancement significantly improves drilling fluid management, contributing to safer and more efficient drilling operations.

This study is devoted to a comparative analysis of modern methods for determining the wax crystallization onset temperature (WCOT) of high-paraffin crude oil from the Uzen field. The objects of investigation were crude oil samples from the 13th reservoir horizon with a paraffin mass content ranging from 22.5% to 27.5%. For the first time in the practice of the oil and gas industry of Kazakhstan, a comprehensive comparison of results obtained using two fundamentally different approaches was performed: the light transmittance method using the KING-UNNP-70 apparatus, which simulates reservoir conditions (pressure of 12 MPa), and a dynamic method using a Wax Flow Loop facility, which reproduces crude oil flow in a pipeline. The experimental results showed that the light transmittance method detects the appearance of the first microcrystals at temperatures of 38.0–41.7 °C, whereas the dynamic method yields higher WCOT values, ranging from 41.0 °C to 44.0 °C. It was also found that the temperature of bulk crystallization, characterizing intensive solid phase formation, lies within the range of 33.5–35.0 °C. The results confirm that under flow conditions, paraffin crystallization begins at higher temperatures compared to static conditions, which is of critical importance for the design of crude oil gathering and transportation systems. The obtained data allow more accurate prediction of the risks of asphaltene–resin–paraffin deposits (ARPD) formation and optimization of technological operating conditions of wells at the late stage of field development.

This study presents the development of an advanced 215.9 mm drill bit with an optimized material distribution to enhance wear resistance, durability, and operational efficiency in highly abrasive formations. A comprehensive scanning electron microscopy (SEM) analysis of the powders used in the drill bit's construction was conducted using the TESCAN Mira 3 LMU system. The analysis included tungsten carbide–cobalt (WC–Co) and diamond-containing composite powders. The results revealed that WC–Co powders exhibit high density and uniform particle distribution, making them suitable for load-bearing components, while diamond-containing powders ensure superior cutting performance and wear resistance. Based on these findings, a rational material allocation was implemented: WC–Co-based materials were used for structural elements, and diamond-containing powders were applied in cutting and undercutting inserts. Process was optimized to prevent thermal degradation of the polycrystalline diamond compact (PDC) inserts. The developed drill bit was designed for rotary drilling with an axial load range of 20–80 kN, rotation speeds of 80–250 rpm, and a drilling fluid flow rate of up to 40 L/s. The proposed design is particularly suited for the geological and technical conditions of Kazakhstan’s oil and gas fields, contributing to reduced drilling costs and increased efficiency.