• Energy Research
• chemical engineering close

Abstract Dimethyl ether appears to be a better choice among various diesel alternatives due to its high cetane number and sootless combustion. However, the physical and chemical properties of dimethyl ether are very different from those of diesel. The physical properties influence spray formation and atomization characteristics, while chemical properties determine combustion and emission formation characteristics. Thus, fuel's physical and chemical properties significantly determine engine performance and emissions. In the present work, spray combustion and emission formation characteristics of n-heptane, dimethyl ether, and their blends (10, 25, and 50% dimethyl ether in n-heptane) were numerically studied in a constant volume chamber. Results show that the n-heptane spray combustion has the highest heat release rate with an intense premix combustion phase, whereas dimethyl ether spray combustion has the lowest heat release rate and shortest premix combustion phase. The magnitude of the premixed phase and heat release rate decreases with the increase in dimethyl ether mass fraction in the blends. Soot, carbon monoxide (CO), unburned hydrocarbon (UHC), and nitric oxide (NO) emissions decreased with the increase in the dimethyl ether mass fraction in the blends and were lowest for the dimethyl ether.

AbstractThe fluid flow characteristics in shale fractures are of great significance for shale gas reservoir evaluation and exploitation. In this study, artificial tension fractures in shale were used to simulate the hydraulic fractures formed by fracturing, and a gas flow test under different pressure gradients was conducted. The nonlinear gas flow and stress‐dependent permeability characteristics were analyzed. The experimental results show the following: (a) CO2 flow in shale fractures exhibits strong nonlinearity. Forchheimer's law, which considers gas compressibility, satisfactorily describes the nonlinear relationship between the flow rate and the pressure gradients in shale fractures. (b) The permeability sensitivity of shale fractures under stress is very strong, and the exponential relationship better describes the pressure dependency of the permeability for the tested shale samples. The permeability of the shale fractures is similar when measured parallel or perpendicular to bedding. Furthermore, the pressure dependence of fractures in shale obeys the Walsh permeability model. (c) As the effective stress increases, the nonlinear flow behavior appears earlier. Based on the Reynolds number and the nonlinear coefficient, a friction factor model is proposed. (d) The normalized transmissivity exhibits a strong correlation with the Reynolds number. CO2 flow through shale fractures is generally dominated by transitional flow. The critical Reynolds number ranges from 1.8 to 102.88 and decreases with increasing effective stress.

Abstract Partial least square regression (PLS-R) methodology have been applied on dataset containing FTIR spectra and densities for a large set of MEA solvent samples. The prediction capabilities for the major compounds were tested on different set of realistic degraded solvent samples ranging from bench scale experiments to pilot plant campaigns. Generally, the methods showed good results with exception of samples with high amount of heat stabile salts (HSS). For the real samples, sample residuals (i.e. part of data not fitted by the model) were also studied, and a clear correlation between the residuals and HSS level in samples were observed. Online techniques based on PLS-R and FTIR should be an attractive alternative for monitoring the major solvent compounds in CO2 capture plants using amine solvents, as this will reduce cost of chemical analysis and could be an important tool for implementation of control strategies for energy saving in the process.

Abstract Wellbore pressure gradient in gas wells is significant in designing deliquification technologies and optimizing production. At present, no model has yet to be established specifically for gas wells at a wide gas flowrate range. When calculating pressure gradient in a specific gas field, engineers must evaluate these widely used models and get the best performance model at a certain range. To establish a more comprehensive model in horizontal gas wells, an experimental study was conducted to investigate the flow behavior of liquid-gas two-phase flow at different gas and liquid velocities and inclined angles in a 50 mm visual pipe. The evaluation of these widely used models against the experimental data shows that no model can predict liquid holdup at different gas velocity ranges, and huge deviations due to several reasons can be observed. After conducting a comprehensive analysis, a new liquid holdup correlation was proposed based on the Mukherjee–Brill model by correlating from the experimental results, which have parametric ranges closer to the production of gas wells. This new model adopts a new dimensionless gas velocity number to characterize flow similarities and better scale up pressure from the experiment to the gas wells. By validating against experimental data and field data, the results indicate that the new two-phase flow model has stable performance and can accurately predict pressure gradients at different ranges of pressure and gas/liquid velocities.

Abstract Fractures along interfaces between host rock and wellbore cement have long been identified as potential CO2 leakage pathways from subsurface CO2 storage sites. As a consequence, cement alteration due to exposure to CO2 has been studied extensively to assess wellbore integrity. Previous studies have focused on the changes to either chemical or mechanical properties of cement upon exposure to CO2-enriched brine, but not on the effects of loading conditions. This paper aims to correct this deficit by considering the combined effects of the fracture pathway and changing effective stress on chemical and mechanical degradation at conditions relevant to geologic carbon storage. Flow-through experiments on fractured cores composed of cement and tight sandstone caprock halves were conducted to study the alteration of cement due to exposure to CO2-enriched brine at 3, 7, 9, and 12 MPa effective stress. We characterized relevant reactions via solution chemistry; fracture permeability via changes to differential pressure; mechanical changes via micro-hardness testing, and pore structure changes via x-ray tomography. This study showed that the nature and the rates of the chemical reactions between cement and CO2 were not affected by the effective stress. The differences in the permeability responses of the fractures were attributed to interactions among the geometry of the flow path, the porosity increase of the reacted cement, and the mechanical deformation of reacted asperities. The suite of observed chemical reactions contributed to change in cement mechanical properties. Compared to the unreacted cement, the average hardness of the amorphous silica and depleted layers was decreased while the hardness of the calcite layer was increased. Tomographic imaging showed that preferential flow paths formed in some of the core-flood experiments, which had a significant impact on the permeability response of the fractured samples. We interpreted the observed permeability responses in terms of competition between dissolution of cement phases (leading to enhanced permeability) and mechanical deformation of reacted regions (leading to reduced permeability).

Abstract In this study, the effects of the different concentrations of hydrochloric acid, hydrofluoric acid, and acetic acid and a surfactant on the physicochemical characteristics of coal, such as pore diameter distribution, pore fractal dimension, and chemical structures were studied. The wettability performance of the reagent-modified coal was proposed. The results demonstrated that the mineral dissolution rate of HF in the coal sample was much higher than those by HCl and HAC treatment, which increases the surface roughness of coal. With the increase in the concentration of a multicomponent acid solution, the number of micropores decreased and the number of macropores increased. Moreover, both fractal dimensions D1 and D2 of the coal sample treated with the multicomponent acid comprising 6% HCl, 6% HF, and 6% HAC (#3) were the smallest. This shows that compound reagent #3 is available to enhance the pore size distribution with a better effect than the other five ones. Compared with the raw coal (#7), treatment with high concentrations of HCl (#4) significantly decreased the contact angle on coal (#4), whereas treatment with high concentrations of HF or HAC (#6 or #5), significantly increased it.

AbstractA new setup for accurate measurement of phase behavior of CO2-rich mixtures relevant for CCS has been designed, covering a range between - 60 and 150°C in temperature and 0.4 and 20MPa in pressure. In order to design safe and efficient infrastructure for CCS, the exact properties of these mixtures are required, and currently there are large knowledge gaps that need to be closed regarding the phase behavior. This paper reports a description of the experimental setup, how uncertainties will be verified and contained, and the very first test measurements performed using the setup.

Abstract The Sleipner CO 2 injection project was the world's first industrial offshore CO 2 Capture and Storage (CCS) project with more than 16 Mt CO 2 injected since 1996. Key monitoring insights from Sleipner are the dual interpretation of seismic and gravimetric monitoring surveys to quantify the free CO 2 mass changes and plume geometry development as a function of time. The learnings from Sleipner have contributed to making guidelines for monitoring future CCS injection projects, showing that selection of monitoring technology and the timing and extent of monitoring surveys should be case specific and risk based, while also taking into account the long term nature of CCS projects.