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Nitrogen is of paramount importance for many processes in chemical and petroleum engineering; including enhanced oil recovery, gas injection for pressure maintenance, and gas recycling. Precise estimation of interfacial tension (IFT) between N 2 and the reservoir hydrocarbons is, therefore indispensable. However, experimental measurement of IFT is expensive and time consuming. Therefore, reliable model for estimating IFT is vital. In this communication, the IFT between N 2 and n-alkanes was modeled over a wide range of pressure (0.1–69 MPa) and temperature (295–442 K) based on the principle of corresponding state theory using dimensionless pressure and dimensionless temperature. Three well-known models; namely, Multilayer Perceptron (MLP) Neural Networks ( optimized by Levenberg-Marquardt ( LM ), Scaled Conjugate Gradient (SCG), or Bayesian Regularization (BR)), two Radial Basis Function (RBF) Neural Networks ( optimized by Particle Swarm optimization ( PSO ) technique or Genetic Algorithm ( GA )) and one Least Square Support Vector Machine (LSSVM) ( optimized by coupled simulated annealing ) were used to develop robust and accurate models for predicting IFT based on the proposed dimensionless parameters. Results suggested that the developed MLP-LM was the most accurate model of all with an average absolute relative error of 1.38%. MLP-LM model was compared with three well-known models in the literature; namely Density Gradient Theory (DGT), Linear Gradient Theory (LGT), and Parachor approaches combined with the Volume Translated Predictive Peng Robinson Equation of State (VT-PPR EOS) and the recently developed model by Hemmati-Sarapardeh and Mohagheghian. In addition to the advantage of being normal alkane-independent, results showed that the proposed MLP-LM model is superior to published models. Lastly, the quality of the literature IFT data and the applicability domain of MLP-LM model were evaluated using the Leverage approach. [ABSTRACT FROM AUTHOR]

Enhanced Oil Recovery (EOR) through various methodologies has been an active research for many years seeking efficient methods to increase the crude oil recovery efficiency from oil reservoirs. Among different gas injection scenarios, carbon dioxide (CO 2 ), natural gas (mainly methane (CH 4 )) and nitrogen (N 2 ) injection are considered as promising EOR agents. Asphaltene precipitation and deposition during EOR methods cause severe problems, which affect the recovery efficiency and increase the cost of the incremental oil production. This study is aimed to investigate the effects of CH 4 and N 2 injection compared with CO 2 injection on asphaltene precipitation and deposition. The different mole percent of the mentioned gases were introduced into the high-pressure cell, then the amount of precipitated asphaltene was measured at the reservoir condition. The evolution of asphaltene deposition was monitored through a high-resolution microscope. Moreover, Image processing software was utilized to check the amount of deposited asphaltene and its size distribution under different conditions. The most apparent finding to emerge from this study is that both CO 2 and natural gas increase the amount of precipitated asphaltene whereas the nitrogen as an inert gas has no considerable effect on the amount of precipitated asphaltene. According to the results, the increment of precipitated asphaltene by CO 2 is much higher than natural gas. Further, the thermodynamic solid model used in this study reasonably predicted the trend of asphaltene precipitation process for the mentioned EOR scenarios. [ABSTRACT FROM AUTHOR]

Nitrogen has emerged as an attractive gas for many petroleum and chemical engineering applications such as gas lift, gas recycling, pressure maintenance, and enhanced oil recovery, especially for some high-pressure reservoirs. Accurate determination of interfacial tension (IFT) in nitrogen/hydrocarbon systems is crucial and required for numerous applications in chemical and petroleum industries. The experimental measurements of IFT are costly, cumbersome and time consuming, especially at high pressure-high temperature conditions. In this study, the IFT of normal alkanes from n-C 5 to n-C 16 (as the representatives of crude oil) and nitrogen is modeled at a wide range of pressure (from 0.1 to 69 MPa) and temperature (from 295 to 442 K) using group method of data handling (GMDH). Three inputs were used for modeling including pressure, temperature, and molecular weight of normal alkane. To develop the most efficient model, 60% of the dataset was used for model development and the remaining 40% was used to check the validity and accuracy of the developed model. The proposed model predicts the data satisfactorily with an average absolute relative error of 3.81% and 3.91% in training and testing subsets, respectively. Then, the proposed model was compared to the well-known IFT models, namely Linear Gradient Theory (LGT), Density Gradient Theory (DGT), and Parachor approaches combined with the Volume Translated Predictive Peng Robinson Equation of State (VT-PPR EOS). The results demonstrate that the proposed model not only is superior to the existing models in terms of accuracy, but also can predict the IFT with a simple mathematical expression with a quite low computational cost. Finally, a simple-to-use algorithm was proposed to calculate the minimum miscibility pressure (MMP) in normal alkane/nitrogen systems based on the measurements with vanishing interfacial tension (VIT) technique, which predicts the MMP with high accuracy. [ABSTRACT FROM AUTHOR]

Pre-gas drainage plays a significant role in the prevention of coal and gas outburst in underground coal mines. However, difficulties of reducing the content of coal seam gas, especially localized coal seam CO 2 , to be below threshold values within a given drainage lead time have been encountered in numerous coal mines in Australia. As the proneness of nitrogen outburst is way smaller than CO 2 or methane outburst, nitrogen injection would be an attractive technology for the underground gas drainage management if it is really able to enhance the drainage efficiency. From this point of view, this paper aims at investigating the feasibility of implementing this technology in Bulli seam, Sydney Basin through numerical modelling. Four parts of work were conducted in this paper. Firstly, a binary gas transport model was developed through analysing the binary gas transport mechanism in both coal matrix and coal cleat, and also the matrix-cleat interaction due to binary gas sorption swelling. A real gas mixture viscosity was introduced and its change depends on the molar fractions of both components and their own viscosities. Secondly, the characteristics of the Bulli seam were studied to collect the parameters required by the binary gas transport model. Through laboratory experiment, field investigation and reviewing literature, the coal seam gas (methane, CO 2 ) and nitrogen adsorption and diffusion properties, in-situ seam properties such as permeability, porosity, cleat spacing and virgin pressure are either measured or estimated. Thirdly, the regular drainage effects in six scenarios with different initial permeability and coal seam gas type were examined and three of them are found to have drainage difficulties, i.e., the moderate permeability (0.5 mD) CO 2 case, the low permeability (0.005 mD) methane case and the low permeability (0.005 mD) CO 2 case. The effects of nitrogen injection on enhancing gas drainage efficiency, especially reducing the gas content, are studied for these scenarios. Results show that a satisfactory result is obtained for the moderate permeability CO 2 case, the CO 2 content can be reduced largely and an apparent increase of CO 2 production rate can be seen. However, the effect of nitrogen injection in low permeability methane scenario is even worse than the regular drainage using two boreholes, although it can increase the methane flow rate of single borehole. For low permeability CO 2 case, nitrogen injection can accelerate the reduction ratio of CO 2 content in part of the injection area and increase the total CO 2 flow rate, but the enhanced effect is limited and the CO 2 content is still high after 12 months of injection. Last but not least, the feature of the movement of coal seam gas content peak in the injection area is discussed and the reasons inducing the different injection effects between methane and CO 2 scenarios are analysed. A combination of lateral movement and drop of coal seam gas content peak is found, and permeability is believed to have great impacts on the movement speed. There is no sign indicating either diffusion or permeability change controls the different injection effects between methane and CO 2 scenarios, while the different competitive adsorption characteristics and the increase of mixture gas viscosities may have influences on this difference. [ABSTRACT FROM AUTHOR]

• Field trials of nitrogen injection enhanced gas recovery were carried out in underground coal mine through in-seam boreholes for the first time. • Significant gas flows were observed after nitrogen injections and a strong post-effect was monitored. • Residual gas content (Q3) can be effectively reduced through nitrogen injection and the total recovery ratio of coal seam gas is enhanced. Three stages of nitrogen (N 2) injection enhanced gas drainage through underground in-seam boreholes were carried out in a coal mine located in the southern Sydney basin. Due to the high CO 2 content and low permeability, hard-to-drain coals were encountered during the excavation process in this coal mine. Two parallel in-seam boreholes (the length of 36 m, the diameter of 96 mm and the borehole space of 5 m) were drilled on the rib of the gateroad. A total of ten-cylinder packs of nitrogen (approximately 1500 m3) were injected into the coal seam. Different nitrogen injection pressures (150 KPa, 250 KPa, 350 KPa and 450 KPa) and injection methods (continuous injection and cyclic injection) were employed. Gas flow rates and gas compositions from the production borehole were recorded during and after the nitrogen injection process. It was observed that gas breakthrough was tightly related to the nitrogen injection pressure. The higher injection pressure was, the shorter breakthrough time was. Specifically, no gas breakthrough was obtained when the injection pressure was 150 KPa. The minimum of breakthrough time was 35 min when 450 KPa's injection pressure was employed. Strong post-injection effect was monitored after each stage of injection and it was affected by the volume of the injected nitrogen. Under the current injection conditions, the performances of different injection methods were like each other, which was out of our expectation. After the injections, the results of cores showed that less than 5 % of the total injected nitrogen was remained in the coal seam. The coal seam gas content dropped 0.99–1.65 m3/t after these three stages of injection. All these findings provide implications and guidance not only for laboratory experiment and numerical modelling, but also for the field application of this new technology. [ABSTRACT FROM AUTHOR]