This article provides a detailed analysis of issues related to the complications while drilling in hydrate-bearing rocks of permafrost areas. The goal of the paper is to develop recommendations for preventing gas occurrence while drilling gas hydrate deposits and to eliminate gas leakiness of the intercasing space of the well. The results of modeling the effect of drilling mud injection on the temperature field of the well are presented. It is revealed that the most significant role is played by the injection rate of drilling mud and its temperature. The recommended flow rate of the process fluid should be within 0.30–0.45 m³/s, and its temperature should not exceed 20 °C. Controlling the parameters of drilling mud and its flow rate allows for avoiding intensive gas occurrence while drilling in gas hydrates. The presence of gas hydrates may be the cause of gas leakiness of the intercasing space in the permafrost area. One of the ways to eliminate leakiness is colmatation (clogging). A method of preventing leaks in the intercasing space of the gas well is the use of colmatating solution. An aqueous solution of sodium silicate with the addition of 2% polymer is used as a colmatating composition.

The derivation of commercial naphthalene by rectification is a possible approach in coal-tar processing. Naphthalene is widely used in chemical synthesis for the production of phthalic...

Based on the analysis of a phenol and acetone recovery flowsheet and phase equilibria of reactionmixture components, isopropylbenzene has been proposed for use as an entrainer, which is feedstock for the manufacture of the aforementioned products. By structure optimization, the number of recovery steps has been decreased from eight to five and power consumption has been substantially reduced.

Cementing wellbore intervals in permafrost environments presents significant challenges due to cyclic freeze-thaw conditions, which induce microstructural degradation in the cement sheath, compromising zonal isolation and long-term well integrity. While existing studies have addressed thermal effects on cement properties, the interplay between alternating temperatures, unhydrated fluid behavior, and stress evolution in the pore space remains poorly understood. This study introduces an integrated methodology to systematically investigate the impact of cyclic thermal loads on cement sheath microstructure and mechanical performance under simulated permafrost conditions. A combination of advanced laboratory techniques – including X-ray microtomography, strain gauge monitoring, and controlled thermal cycling – was employed to analyze pore redistribution, microcrack propagation, and stress dynamics. Key findings reveal that unhydrated mixing fluid, trapped in the pore space, undergoes phase transitions during freeze-thaw cycles, generating internal stresses that exceed the cement’s tensile strength, leading to irreversible structural damage. To mitigate these effects, we proposed the use of a synthetic polyacrylamide-based polymer (PAM) as a multifunctional additive. Experimental results demonstrate that PAM reduces fluid loss by 54.76%, enhances compressive strength by 20%, and maintains Young’s modulus (13.1 GPa) after three freeze-thaw cycles. These improvements can be attributed to PAM’s ability to delay fluid loss, redistribute pore stress, and stabilize the cement matrix through enhanced coagulation and gelation mechanisms. The study’s scientific contribution lies in its holistic framework for evaluating cement degradation mechanisms in permafrost, coupled with actionable solutions for optimizing slurry design. This work advances the practical application of polymer-modified cements in Arctic well construction, offering a pathway to improve durability and reduce environmental risks in extreme cold environments.

This study addresses the critical issue of gas influx during the drilling of intervals containing gas hydrates, a common challenge in drilling operations in hydrate-bearing formations. The primary objective of the research is to determine optimal drilling fluid parameters, specifically temperature and flow rate, to mitigate risks associated with gas hydrate dissociation and ensure wellbore stability. The COMSOL Multiphysics software package was used for the simulation. The model integrates Fourier's law of thermal conductivity and heat transfer correlations to simulate the thermal interaction between the drilling fluid and the wellbore. For the first time in drilling process modeling, the thermodynamic state of gas hydrates under the specific conditions of Gubkinskoye field has been integrated. The decomposition potential of hydrates was evaluated using the GHA350 autoclave. The model accounts for the thermobaric conditions of the formation, as well as the gas composition and water formation of the Gubkinskoye gas-condensate field. The simulation was conducted for the depth interval of 250–350 m, with the rock temperature ranging from 270 to 278 K and the drilling fluid temperature varying between 283 and 298 K. This research contributes to the development of safe and more efficient drilling practices, reducing the risks of gas influx and ensuring the stability of wellbores in gas hydrate reservoir. As a result, it was found that the recommended flow rate of drilling mud should be in the range of 0.030–0.045 m3/s, and its temperature should not exceed 293 K.

Using an example of ethylbenzene and diethylbenzene separation, we demonstrate that structured packing with a low specific flow resistance is an effective tool for setting up hardware and energy rectification packages. By replacing conventional plates with structured packing, the flow resistance and vertical temperature gradient are significantly lowered, providing favorable conditions for thermal coupling of the columns. Thermal coupling of the columns in a two-column setup for extraction of rectified ethylbenzene and diethylbenzene provides heating steam savings of 0.13 Gcal per tonne of diethylbenzene.