Heavy Hydrocarbon Components Research Articles

“Component flow” conditions and its effects on enhancing production of continental medium-to-high maturity shale oil

Based on the production curves, changes in hydrocarbon composition and quantities over time, and production systems from key trial production wells in lacustrine shale oil areas in China, fine fraction cutting experiments and molecular dynamics numerical simulations were conducted to investigate the effects of changes in shale oil composition on macroscopic fluidity. The concept of “component flow” for shale oil was proposed, and the formation mechanism and conditions of component flow were discussed. The research reveals findings in four aspects. First, a miscible state of light, medium and heavy hydrocarbons form within micropores/nanopores of underground shale according to similarity and intermiscibility principles, which make components with poor fluidity suspended as molecular aggregates in light and medium hydrocarbon solvents, such as heavy hydrocarbons, thereby decreasing shale oil viscosity and enhancing fluidity and outflows. Second, small-molecule aromatic hydrocarbons act as carriers for component flow, and the higher the content of gaseous and light hydrocarbons, the more conducive it is to inhibit the formation of larger aggregates of heavy components such as resin and asphalt, thus increasing their plastic deformation ability and bringing about better component flow efficiency. Third, higher formation temperatures reduce the viscosity of heavy hydrocarbon components, such as wax, thereby improving their fluidity. Fourth, preservation conditions, formation energy, and production system play important roles in controlling the content of light hydrocarbon components, outflow rate, and forming stable “component flow”, which are crucial factors for the optimal compatibility and maximum flow rate of multi-component hydrocarbons in shale oil. The component flow of underground shale oil is significant for improving single-well production and the cumulative ultimate recovery of shale oil.

Desorption Characteristics of CH4-C2H6 Mixed Gas in Heavy Hydrocarbon-Rich Coal Seams.

The gas desorption characteristics of coal are closely related to the gas content of the coal seam. The gas in heavy hydrocarbon-rich coal seams contains CH4 and C2H6 heavy hydrocarbons. However, most current research on the gas desorption characteristics of coal seams focuses on CH4 analysis, ignoring the influence of the C2H6 heavy hydrocarbon gas. To accurately determine the gas content of a heavy hydrocarbon-rich coal seam, methods based on CH4 analysis are inadequate and the desorption characteristics of CH4-C2H6 mixed gas must be clarified. This work experimentally and theoretically studies the desorption characteristics of single-component gas and CH4-C2H6 mixed gas from coal samples. The results show that increasing the adsorption-equilibrium pressure was found to increase the desorption quantity and desorption speed of single-component gas and increase the desorption quantity, desorption ratio, and diffusion coefficient of mixed gas. Under the same adsorption-equilibrium pressure, the desorption quantity and rate of single-component CH4 gas exceeded those of C2H6. The quantity and speed of mixed gas desorption increased with rising CH4 concentration and decreased with rising C2H6 concentration. The change in the mixed gas concentration during desorption reflects the distribution characteristics of light hydrocarbon components on the outer surface and heavy hydrocarbon components on the inner surface of coal. From the desorption characteristics of mixed gas, desorption models of mixed gas were obtained at different concentrations, laying a theoretical foundation for accurate determinations of gas contents in heavy hydrocarbon-rich coal seams.

A Method for Identifying the Light Oil Layer and Condensate Gas Layer Based on the Distribution of Heavy Hydrocarbon Components

A Method for Identifying the Light Oil Layer and Condensate Gas Layer Based on the Distribution of Heavy Hydrocarbon Components

Molecular dynamics investigation of DME assisted CO2 injection to enhance shale oil recovery in inorganic nanopores

In view of the unsatisfactory improvement effect of pure CO2 injection on the shale oil recovery in microscopic pores, the molecular dynamics method was used to simulate the process of dimethyl ether (DME) assisted CO2 injection in nanopore to recover shale oil. Firstly, cosolvents with different functional groups were selected to assist CO2 injection to compare the enhanced oil recovery (EOR) effect of shale oil. Subsequently, the microscopic mechanism of DME promoting CO2-EOR effect was systematically revealed. Then, the effects of temperature, pressure, DME molar content and shale oil composition on the EOR mechanism of CO2-DME mixture were further studied. Finally, the sensitivity difference of EOR effect to these influencing factors was compared. The research results showed that the EOR effect of DME-assisted CO2 injection (42.96%) is the best, followed by acetone (38.61%), propane (33.38%), ethanol (32.42%) and pure CO2 (22.43%). The microscopic EOR mechanism of DME-assisted CO2 injection includes improving the solubility and competitive adsorption capacity of CO2, as well as reducing oil viscosity and two-phase interfacial tension (IFT). The EOR effect of CO2-DME mixture is the best when the system temperature rises to 100℃, but excessive high temperature has a negative impact on CO2 solubility and intermolecular interaction. The increase of system pressure increases the fluid density, shortens the mass transfer distance, and reduces the IFT, which promotes the solubility, miscibility and competitive adsorption capacity of CO2-DME mixture, thereby continuously improving the shale oil recovery. Although the increase of DME content can improve the competitive adsorption capacity and reduce the IFT, it also reduces the solubility and diffusion capacity. The EOR effect is best when the mole fraction of DME reaches 40%. The increase of the proportion of non-hydrocarbon compounds and heavy hydrocarbon components reduces the solubility, miscibility and competitive adsorption capacity of CO2, and the negative impact of the former is greater than that of the latter. The EOR effect of DME-assisted CO2 injection on shale oil is most affected by pressure, followed by DME mole fraction, temperature, and oil composition.

Study on Homogeneous Reduction Technology in Gas Samples for Oil and Gas Loss

The process of storing oil depots and combined station tanks is affected by factors such as process technology, equipment, and management methods. Inevitably, some heavy hydrocarbon components will condense. According to the available literature, the existing detection methods are not enough to accurately measure the component composition so that the proportion of heavy hydrocarbon substances in the lost gas is reduced. In this paper, by inventing a homogeneous reduction device, the lost gas in the entire laboratory process was kept in a homogeneous state so that the gas components were well-retained. Using the homogeneous reduction method and a traditional inspection method, gas chromatography was performed on a standard gas and the on-site lost gas, respectively. The standard gas measurement results show that the mean deviations of the homogeneous reduction method and the traditional test method were −3.45% and −11.62%, respectively, and the reduction degree reached 96.55% with the homogeneous reduction method. The results of the on-site gas loss measurements show that the proportions of most hydrocarbon substances in each lost gas increase to varying degrees after using the homogeneous reduction technology. Therefore, it is proved that these components can be better preserved using the homogeneous reduction method. It can effectively avoid the condensation of components, which is of great significance to the study of oil and gas loss.

Experimental study on the influence of fractured-vuggy porous media on condensate gas depletion production

The dew point pressure can be obtained by conventional condensate gas phase test in PVT cylinders. However, in condensate gas reservoirs, the fluid interacts with the fractured-vuggy porous media, which makes the depletion process of condensate gas in pores, fractures or vugs different from that in PVT cylinder. In order to study the mechanism of this difference, three different experimental models were made to carry out the condensate gas depletion production experiment. The results showed that the existence of fracture-vuggy porous media would affect the depletion production process. The pores, fractures and vugs increased the dew point pressure from 26.2 MPa to 26.6 MPa and decreased the condensate oil recovery from 72.8% to 70.7%. When the fractures, vugs and pores are filled with powered fine sand of carbonate rocks, the dew point pressure reaches 27.4 MPa and the condensate oil recovery reduces to 68.4%. The fractured-vuggy porous media will aggravate the retro condensation phenomenon, promote the accumulation of heavy hydrocarbon components on the pore surface and precipitate in the form of condensate oil and hinder the recovery of condensate oil. This work explains the mechanism of the influence of fractured-vuggy porous media on the phase behavior of condensate gas.

Genesis Types and Migration of Middle and Lower Assemblages of Natural Gas in the Eastern Belt around the Penyijingxi Sag of the Junggar Basin, NW China

This study analyzes the geochemical characteristics of natural gas composition, carbon isotope, and light hydrocarbon in the eastern belt around the Penyijingxi sag of the Junggar Basin. The result shows the that natural gas content is dominated by alkane gas, with low contents of heavy hydrocarbon and non-hydrocarbon components. The overall carbon isotopic composition of the alkanes shows a trend as δ13methane (C1) < δ13ethane (C2) < δ13propane (C3) < δ13butane (C4), and all δ13C1 values are <−30‰, which are typical of gases of organic origin. The natural gas is mainly coal-derived gas from the Lower Urho formation, mixed with a small amount of oil-associated gas from the Fengcheng formation. The vertical migration of natural gas resulted in the mixing of oil-associated gas and coal-derived gas and the mixing of alkane gas at different stages of the same origin, which should be the origin of carbon isotope inversion. The diffusion migration of carboniferous oil and gas reservoirs has led to differences in gas geochemical characteristics among gas wells. These migration characteristics of natural gas may indicate that the shallow layers are a favorable stratum for the next step of oil and gas exploration in the eastern belt around the Penyijingxi sag.

Study on Pyrolysis-Mechanics-Seepage Behavior of Oil Shale in a Closed System Subject to Real-Time Temperature Variations.

In situ mining is a practical and feasible technology for extracting oil shale. However, the extracted oil shale is subject to formation stress. This study systematically investigates the pyrolysis–mechanics–seepage problems of oil shale exploitation, which are subject to thermomechanical coupling using a thermal simulation experimental device representing a closed system, high-temperature rock mechanics testing system, and high-temperature triaxial permeability testing device. The results reveal the following. (i) The yield of gaseous hydrocarbon in the closed system increases throughout the pyrolysis reaction. Due to secondary cracking, the production of light and heavy hydrocarbon components first increases, and then decreases during the pyrolysis reaction. The parallel first-order reaction kinetic model shows a good fit with the pyrolysis and hydrocarbon generation processes of oil shale. With increasing temperature, the hydrocarbon generation conversion rate gradually increases, and the uniaxial compressive strength of oil shale was found to initially decrease and then increase. The compressive strength was the lowest at 400 °C, and the conversion rate of hydrocarbon formation gradually increased. The transformation of kaolinite into metakaolinite at high temperatures is the primary reason for the increase in compressive strength of oil shale at 400–600 °C. (ii) When the temperature is between 20 and 400 °C, the magnitude of oil shale permeability under stress is small (~10−2 md). When the temperature exceeds 400 °C, the permeability of the oil shale is large, and it decreases approximately linearly with increasing pore pressure, which is attributed to the joint action of the gas slippage effect, adsorption effect, and effective stress. The results of this research provide a basis for high efficiency in situ exploitation of oil shale.

Experimental Analysis and Performance Investigation of Immiscible Super-Critical CO2 Flooding Processes in Tight Oil Reservoir

CO2 flooding, a promising technique of enhanced oil recovery, is widely used for its capability of boosting oil recovery, and reducing greenhouse gas emissions. In this study, the oil displacement performance of supercritical CO2 is tested in laboratory under immiscible flooding. The results show that: Supercritical CO2 improves oil recovery, by virtue of its low viscosity, high diffusivity, and easy dissolution. With the same pore volume (PV), supercritical CO2 flooding significantly boosted the oil recovery factor. The factor reached the maximum, when almost 1.5PV of CO2 was injected. As CO2 moved from the gas phase to the supercritical state, the oil displacement efficiency increased by 10%. To obtain the same oil recovery factor, non-supercritical flooding needed to inject more CO2 than supercritical flooding. Light hydrocarbon components (C1-7) in crude oil were gradually extracted before CO2 breakthrough, while heavy hydrocarbon components (C7+) were extracted mainly after CO2 breakthrough. In addition, supercritical CO2 flooding extracted more intermediate hydrocarbons than critical CO2 flooding. To sum up, supercritical flooding outperforms non-supercritical flooding in injection performance, oil displacement efficiency, and oil exchange rate.

Purification of hydrogen from natural gas/hydrogen pipeline mixtures

• A six-bed PSA cycle is proposed for the purification of hydrogen/natural gas mixture. • A three adsorbent layered bed is able to handle realistic natural gas mixtures. • High purity hydrogen (>99%) was obtained for hydrogen feed concentrations of 5–30%. • PSA compares well with an electrolyzer in providing hydrogen to a refueling station. There is an increasing global attention toward hydrogen as a green energy carrier, primarily because of the environmental concerns associated with global warming issues. It is expected that the produced hydrogen from various sources may be injected to the natural gas grid for economical transportation and use. One interesting option is to evaluate technologies for extracting the hydrogen from the natural gas pipeline for applications using high purity hydrogen. However, natural gas is a complex mixture including CH 4 , C 2 H 6 , CO 2 , N 2 and trace amounts of C 3 -C 6 hydrocarbons. This function requires a natural gas/hydrogen separation technology which must not only operate with low capital and energy cost, but must also provide hydrogen of sufficient purity. The goal of current work therefore was to take a mixture of hydrogen/natural gas of representative concentrations and produce high purity hydrogen using a bespoke pressure swing adsorption (PSA) cycle. A six-bed PSA system with 12 steps was developed and simulated in Aspen Adsorption software to this end. A three-layered adsorption column was designed to capture different groups of components of the mixture selectively within each layer. Informed by measured and literature equilibrium isotherm data, silica gel was chosen as the pre-layer to remove heavy hydrocarbon components and most of the CO 2 ; activated carbon in the main-layer to mainly adsorb methane, and LiLSX zeolite in the top-layer to remove trace nitrogen which had eluted from the earlier layers, for obtaining pure hydrogen product. High purity hydrogen product (>99%) with high recovery (>85%) was achieved with the PSA system for different hydrogen concentrations (5–30%) in the 30 bar feed stream. We also compared the PSA system against an electrolyzer generating hydrogen onsite. Our analysis suggests that the PSA competes favorably, even at a low hydrogen recovery of 40% in cases where the PSA plant is built at a pressure reduction station.

Immiscible/Near-Miscible relative permeability for confined fluids at high-pressure and high-temperature for a fractal reservoir

The complex interaction between fluids and solids in reservoirs includes interface slip, capillary confinement and the diffusion and mass transfer between CO2 and oil and results in intensely nonlinear flow complexity. This study proposes a relative permeability model that accommodates a fractal pore size distribution and honors these complex process interactions. The relative permeability to CO2 flooding, in the near-miscible region, is predicted through interpolation based on the Gibbs free energy (GFE). The thermodynamic phase behavior of the fluids in the nanopores is considered by applying critical shifts in the temperatures and pressures. A volume-translated Peng-Robinson equation of state is used to calculate the CO2 and n-alkane densities to high reservoir pressure. Fluid-based correlation and modified volumetric mixing rules are then used to extend the viscosity calculations to mixtures with heavy hydrocarbon components. Predictions from the proposed model better fit experimental observations relative to previous models similarly incorporating fractal theory. The nanopores are shown to increase the relative permeability of the non-wetting phase by decreasing the viscosity ratio of the two phases. Increasing key parameters that are related to the pore structure, e.g. the fractal dimension, Df, and critical pore radius, rc, increases the relative permeability of the non-wetting phase. The GFE-based interpolation contributes to the smooth and continuous change in the relative permeability parameters local to the critical point of the mixture, with the confined fluid more likely to be miscible at the same pressure than the bulk fluid. This model can be integrated with a compositional simulator to solve field-scale problems but accommodating the micro-scale physics of unconventional reservoirs.

Molecular and Carbon Isotopic Variation during Canister Degassing of Terrestrial Shale: A Case Study from Xiahuayuan Formation in the Xuanhua Basin, North China

Molecular and carbon isotopic variation during degassing process have been observed in marine shale reservoirs, however, this behavior remains largely unexplored in terrestrial shale reservoirs. Here, we investigate the rock parameters of five terrestrial shale core samples from the Xiahuayuan Formation and the geochemical parameters of thirty natural gas samples collected during field canister degassing experiments. Based on these new data, the gas composition and carbon isotope variation during canister degassing are discussed and, further, the relationship between petrophysics and the carbon isotope variation is explored. The results show that methane content first increases and then decreases, the concentrations of carbon dioxide (CO2) and nitrogen gas (N2) peak in the early degassing stage, while heavier hydrocarbons gradually increase over time. Shale gas generated from humic source rocks contains more non-hydrocarbon and less heavy hydrocarbon components than that generated from sapropelic source rocks with similar maturity. Time-series sampling presents an upward increase in δ13C1 value during the degassing process with the largest variation up to 5.7‰, while the variation in δ13C3 and δ13C2 is insignificant compared to δ13C1. Moreover, we find that there is only a small variation in δ13C1 in shale samples with high permeability and relatively undeveloped micropores, which is similar to the limited δ13C1 variation in conventional natural gas. For our studied samples, the degree of carbon isotope variation is positively correlated with the TOC content, micropore volume, and micropore surface, suggesting that these three factors may play a significant role in carbon isotope shifts during shale gas degassing. We further propose that the strong 13C1 and C2+depletion of shale gas observed during the early degassing stage may have resulted from the desorption and diffusion effect, which may lead to deviation in the identification of natural gas origin. It is therefore shale gas of the late degassing stage that would be more suitable for study to reduce analytic deviations. In most samples investigated, significant isotopic variation occurred during the degassing stage at room temperature, indicating that the adsorbed gas had already been desorbed at this stage Our results therefore suggest that more parameters may need to be considered when evaluating the lost gas of shales.

Insights into recovery of multi-component shale gas by CO2 injection: A molecular perspective

Understanding the mechanism behind shale gas recovery is of great importance for achieving optimum shale gas productivity. In this work, we use Grand Canonical Monte Carlo (GCMC) simulations to investigate the adsorption and recovery mechanisms of ternary hydrocarbon mixtures comprising methane, ethane and propane in kerogen nanopores. For the adsorption of hydrocarbon mixtures in kerogen slit pores, density distributions of each component are analyzed and the results indicate that densities of methane and ethane in the first adsorption layer increase as pressure increases, while an opposite trend is observed for propane. A stronger confinement effect is observed on the heavier hydrocarbon components, increasing the difficulty of recovery. For the recovery of the multi-component shale gas, we propose a reference recovery route with pressure drawdown and CO2 injection combined and the recovery efficiency is compared to the condition with only pressure drawdown applied. Significant enhancement in recovery ratio for all three components is observed with the CO2 injection and a better performance is shown on heavier components and smaller pores. An increase of 60% and 40% in propane recovery ratio is achieved in the 2-nm and 4-nm kerogen slit pores, respectively. Recovery mechanisms of pressure drawdown and CO2 injection are investigated in detail. The pressure drawdown method recovers methane from the first adsorption layer and middle of slit pore simultaneously, while extracting ethane and propane mainly from the middle of slit pore; the recovery due to CO2 injection mainly takes place in the adsorption layers. Pressure drawdown tends to extract the lighter components and CO2 injection is efficient in the recovery of heavier hydrocarbons. As pore width increases, the recovery ratio of pressure drawdown increases, while that of CO2 injection decreases. Besides, the CO2 sequestration ratio is higher in smaller kerogen slit pores.

Phase Behavior of Hydrocarbon Mixtures for the Low Concentration of Heavy Hydrocarbon Components

The present work shows the accurate calorimetric measurements of phase equilibria of hydrocarbon mixtures for the low concentration of heavy hydrocarbon components in particular the system methane + propane + decane with special emphasis on the concentration of decane below one mole percentage. Heat capacity, internal energy, pressure, and temperature derivative of pressure at constant volume for the ternary system have been measured in the range of 100–370 K and 0.1–40 MPa. To show a procedure of the phase diagram plotting by a precision adiabatic calorimetry, the typical phase diagram for a hydrocarbon mixture has been plotted in detail. A phase diagram has been plotted based on the experimental data of heat capacity, internal energy, pressure, and temperature derivative of pressure at constant volume. A phase transition is localized by a finite discontinuity in a temperature derivative of the thermodynamic potential. A closed area surrounded by the typical phase envelope for a pressure–temperature diagram is the two-phase region. Our particular attention is paid to the ternary system methane + propane + heavy hydrocarbon component for the low concentration of heavy hydrocarbon, in particular, of decane, due to the fact the conventional PVT approach does not guarantee the efficiency and accuracy of the phase diagram plotting for this system. Our investigations show the phase behavior of a hydrocarbon mixture for the low concentration of decane is drastically transformed compared to the customary concept. The hydrocarbon mixture splits into two phases, a macrophase enriched by methane and propane (a decane-poor phase) and a decane-rich microphase. To prove that all phases are equilibrium phases, a cooling mode of measurements is used. At the cooling mode of measurements, the same phase transitions as at the heating mode occur. These phase transitions correspond to the formation of a decane-rich microphase and a macrophase enriched by methane and propane.

Evaluation of gas separator effect on operability of gas-motor piston compressor valves

To increase the efficiency of gas-lift oil and gas production, it is necessary to improve the operation of compressor stations, namely, to increase the reliability of the gas-motor piston compressor units installed in them. It is found that one of the vulnerable units affecting the reliability and efficiency of the gas-motor piston compressor are direct-flow self-acting valves.In the process of preparing gas for transportation, as well as to ensure the reliability and efficiency of the entire production process, it is necessary to eliminate all gas leaks, prevent liquid hydrocarbon components and solids from entering the valve plates.To solve this problem, associated petroleum gas must be cleaned from solids, heavy hydrocarbon components and moisture. To this end, it is recommended to install an additional new design horizontal gas separator on the suction line of gas-motor piston compressors.The usefulness and importance of the new gas separator lie in a more efficient cleaning of associated petroleum gas supplied to the suction of the 1st stage compressor cylinders, which improves compressor performance, minimizing the leakage of valve plates.The new design separator is used to clean gas from coarse and fine-grained dropping liquid, partially liquid in the vapor-phase state and solids. The new separator can also be used in various sectors of the oil and gas industry.The purpose of installing a new gas separator is to increase the efficiency of gas cleaning from liquid and solid impurities

Dynamic simulation of fuel tank aging for LNG‐fueled ship apparatus in an X‐DF Otto cycle engine

AbstractThe increased density in a liquefied natural gas (LNG) tank caused by boil‐off gas (BOG) is a key factor to consider for LNG‐fueled ships with Otto cycle engines. This study conducted dynamic simulation using Aspen HYSYS to solve LNG aging in the fuel gas supply system (FGSS) of an extra‐long stroke dual fuel (X‐DF) engine. The aging phenomenon is severe in the Otto cycle internal combustion engine because heavy hydrocarbon (HHC) components must be removed during the process to satisfy the methane number (MN) requirement. HHC components such as ethane, propane, butane are separated in the HHC removal process so that HHC can be returned to the LNG storage or fuel tank without increased risk of equipment failure relative to steady‐state design conditions. Dynamic process simulations for four cases were conducted to verify the behavior of LNG aging for two fuel compositions and two fuel tank capacities. The results indicate that the different composition of LNG affects the pump duty, the duty of heat exchanger and BOG compressor in steady‐state simulation. Additionally, based on the analysis results, solutions to the problem caused by LNG aging for the FGSS in an X‐DF engine were provided.

Evaluation of source rock potential and hydrocarbon composition of oil sand and associated clay deposits from the Eastern Dahomey Basin, Nigeria

Oil sands are classified as unconventional hydrocarbon plays and are being exploited to augment global energy needs. Nigeria has the largest conventional oil industry in Africa, but is also endowed with abundant oil sand deposits found within the Afowo Formation of the Eastern Dahomey Basin. In this study, outcrop samples of clay, oil sand, and bitumen seepage from a forestry reserve (J4) in Ogun State, South Western Nigeria were evaluated for organic matter maturity and hydrocarbon composition. Pyrolysis results for the clay indicate that the total organic carbon ranges from 5.95 to 18.46 wt % with a maturation temperature (Tmax) within the range of 417–426 °C. A complementary gas chromatography (GC) analysis of the free hydrocarbons in the clay reveals that both light and heavy hydrocarbon components are present. In contrast, oil sand and bitumen contain mostly heavy end hydrocarbon components with hydrocarbon chains C6–C12 missing, confirming oil biodegradation. This study demonstrates that these oil sands and clays represent viable exploration targets. With vast oil sand deposits in the Eastern Dahomey Basin, exploration and exploitation of this resource will open new frontiers to increase Nigeria's hydrocarbon production.

Comparison of reaction media of Aquathermolysis: water in different physical states

The experimental results and the character of the heavy oil transformation in a vapor-air medium, at temperatures and pressures providing the water availability in superheated steam state, in addition in subcritical and supercritical states are shown. Due to various thermodynamic conditions, there was the detection that water reactivity to the transformation of heavy oil hydrocarbon components is different. It was proved that supercritical water ensures the vastest yield of light fractions, boiling point of which is above 350 °C

A Fundamental Micro Scale Study of the Roles of Associated Gas Content and Different Classes of Hydrocarbons on the Dominant Oil Recovery Mechanism by CWI

Various studies demonstrated new gaseous phase formation and oil swelling and viscosity reduction are the oil recovery mechanisms by carbonated water injection (CWI) with new gaseous phase formation being the major recovery mechanism for live oil systems. However, none of the previous studies investigated the influences of dissolved gas content of the oil and oil composition, on the new gaseous phase. This study attempts to provide insights on this area. Based on the results, during CWI as CO2 partitions into the oil the dissolved gas of the oil liberates, which leads to in-situ new gaseous phase formation. The dissolved gas content of the crude oil has a direct impact on the saturation and growth rate of the new gaseous phase. The new gaseous phase doesn’t form for oils that have an infinite capacity for dissolving CO2, such as light pure hydrocarbon components. Oils with limited capacity for dissolving CO2, such as heavy hydrocarbon components, are responsible for the formation of the new gaseous phase. Therefore for a live crude oil, the relatively heavier fractions of oil are responsible for triggering of the new gaseous phase and light to intermediate oil components control the further growth of the new gaseous phase.

GEOMETRY OPTIMIZATION OF 3S-SEPARATOR AS A REDUCING DEVICE FOR LOW-TEMPERATURE TECHNOLOGY

Background Before transporting by gas pipelines, the gas field borehole products must be treated at the complex gas treatment unit (CGTU). Crude gas need to be dried and stripped after initial purification from mechanical impurities. Currently, for well products treating, low temperature separation (LTS) method has become widespread. The products got from the LTS unit are dried and stripped natural gas and stabilized hydrocarbon condensate. The condensate can be used as a raw material for petroleum products, the cost of which is many times higher than the cost of gas fuel. In addition to the economic benefits of separating heavy hydrocarbons, there is a technological need for the process considered. It is in the fact that heavy hydrocarbon components can condense at gas transport temperatures. The consequence of this may be the transport of a two-phase flow - gas and gas condensate. A technically simple and economically less expensive way of cooling a gas to the hydrocarbon dew point temperature at a gas treatment unit is the iso-enthalpy expansion of the gas through the use of a throttling valve. Despite the obvious operational and economic advantages, the LTS using a throttle has several drawbacks (the main of which will be low efficiency when operating the field at the stage of falling pressure). Thus, it is necessary to develop effective and technologically simple methods for implementing the low-temperature separation process. Promising directions are the rationalization of the use of the throttle effect, as well as the optimization of the separator at the stage of falling inlet pressure. Aims and Objectives Development of an algorithm for calculating nozzle geometry and a method for predicting the properties of a gas stream. These studies will allow to move on to creating a real model and conducting bench tests. Results The nozzle geometry based on the composition of the mixture being cooled was calculated, and analysis of the gas parameters during the passage of the nozzle cavity through the stream was carried out. The values of the main parameters of the gas flow were determined by the calculation method in the ANSYS Fluent software package. It was necessary to obtain the convergence of the calculations obtained in the software environment and using the analytical method. The optimal geometry of the nozzle profile in a wide operating range of the input pressure and gas temperature was determined.