• Energy Research

Environmental concern for our planet has changed significantly over time due to climate change, caused by an increasing population and the subsequent demand for electricity, and thus increased power generation. Considering that natural gas is regarded as a promising fuel for such a purpose, the need to integrate carbon capture technologies in such plants is becoming a necessity, if gas power plants are to be aligned with the reduction of CO2 in the atmosphere, through understanding the capturing efficacy of different absorbents under different operating conditions. Therefore, this study provided for the first time the comparison of available absorbents in relation to amine solvents (MEA, DEA, and DEA) CO2 removal efficiency, cost, and recirculation rate to achieve Climate change action through caron capture without causing absorbent disintegration. The study analyzed Flue under different amine-based solvent solutions (monoethanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA)), in order to compare their potential for CO2 reduction under different operating conditions and costs. This was simulated using ProMax 5.0 software modeled as a simple absorber tower to absorb CO2 from flue gas. Furthermore, MEA, DEA, and MDEA adsorbents were used with a temperature of 38 °C and their concentration varied from 10 to 15%. Circulation rates of 200–300 m3/h were used for each concentration and solvent. The findings deduced that MEA is a promising solvent compared to DEA and MDEA in terms of the highest CO2 captured; however, it is limited at the top outlet for clean flue gas, which contained 3.6295% of CO2 and less than half a percent of DEA and MDEA, but this can be addressed either by increasing the concentration to 15% or increasing the MEA circulation rate to 300 m3/h.

The article reflects results of the experimental studies on the modifying agent’s dispersion to\ud affect the nature of its distribution in the total volume of cement stone. An attempt was made to evaluate\ud the strength and filtration properties of the cement stone with respect to the heterogeneity of its structure.\ud The effect of a character of the modifying additive distribution on the permeability and strength of the\ud cement stone was investigated, as a result it was clarified that the zone of influence of the applied dynamic\ud load does not depend on the heterogeneity of the plugging material, and the values of deformation in the\ud cement stone depend on the dispersion, the nature of the distribution of the additive in the volume of the\ud cement stone, the period of the modifying agent activation.\ud The dynamic loads, which most strongly provoke the destruction of cement stone under the influence\ud of high stresses, are considered. Using the finite element method (FEM), the ANSYS application program\ud evaluated stresses in a cemented column, describes the process of deformation of cement stone, taking into\ud account the heterogeneity of its structure.\ud Based on the variability of the additive location, channel models for the most preferred localization of\ud the modifying additive have been determined as open through cracks.\ud The application of the mathematical model, which was elaborated, demonstrates a possibility of the\ud maximum reduction of the water conductivity if the optimal distribution of the modifying additive in the\ud matrix of the cement stone provided.

Most research on CO2 flooding is focusing on CO2 storage than CH4 recovery and mostly simulation-based. To our knowledge, there have been limited reported experimental on CO2 injections capable of unlocking a high amount of the residual methane due to their miscibility effect. The empirical study has highlighted the impact of N2 as a buster gas during the Enhanced Gas Recovery (EGR) process by CO2 flooding. The N2 acts as a buster by re-pressurising the reservoir pressure before the CO2 breakthrough, enabling more CH4 recovery. It also acts as a retardant by creating a thin barrier at the CO2–CH4 interface, making it difficult for the CO2 to disperse into the CH4. This result in an extendable breakthrough, influencing the injected CO2 to migrate downward due to gravity for storage within the pore spaces. This study, a core flooding experiment at 1500 psig and 40 °C of pressure and temperature, respectively, was carried out to study the effect of N2 as buster gas during natural displacement in a porous medium (sandstone rock). The recoveries with N2 buster were better off than those without N2 buster (conventional CO2 flooding). Overall, an improved CH4 recovery and dispersion coefficient with substantial storage was noticed, with the optimum at 0.13 fraction of pore volume buster gas. Compared to the 0.4 ml/min optimum conventional CO2 injection, the results show a 10.64 and 24.84% increase in CH4 recovery and CO2 storage, respectively. 0.71 × 10-8 m2/s reduction in dispersion coefficient was recorded than the convention method. The additional CH4 recovery can provide extra revenue to offsets other operational expenses. This research signifies the potential of N2 as a buster medium on CH4 recovery, which can be applicable for pilot application within the oil and gas industry.

AbstractThe promotion of enhanced gas recovery (EGR) and CO2 storage is still shrouded in contention and is not well accepted, due to the excessive in situ CO2 mixing with the nascent natural gas. This adulterates the recovered CH4 and thus results in a high sweetening process cost thereby making the technique impractical. This has not only limited the field application of EGR in actual projects to a few trails but renders it uneconomical. This study aims to present, experimentally, alternating N2 injection as a potential technique for EGR and CO2 storage in sandstone rock cores. A laboratory core flooding experiment was carried out to simulate a detailed process of unsteady-state methane (CH4) displacement using Bandera grey core plug. This was carried out at 40 °C, 1500 psig, and 0.4 ml/min injection rate by alternative injection of N2 and CO2 in succession designed to suit the application based on optimum operating conditions. The results show that both CO2 storage capacity and CH4 recovery improved significantly when gas alternating gas (GAG) injection was considered. The best results were observed at lower N2 cushion volumes (1 and 2 PV). Therefore, the GAG injection method with N2 as cushion gas can potentially increase both CO2 storage and CH4 recovery of the gas reservoir. This technique if employed will assert the current position and provide vital information for further researches aimed at promoting environmental sustainability and economic viability of the EGR and CO2 sequestration processes.

{"references": ["Johnson, S., Salehi, M., Eisert, K. & Fox, S. 2009. Using Biosurfactants Produced from Agriculture Process Waste Streams to Improve Oil Recovery in Fractured Carbonate Reservoirs.", "De Lima, A. M. & De Souzaa, R. R. 2014. Use of Sugar Cane Vinasse as Substrate for Biosurfactant Production Using Bacillus subtilis PC. Chemical Engineering, 37.", "Filho, J. H., Carioca, O. B., Gonzales, R. B., De Lucena, L. & Tavares, C. A. 2012. Biosurfactants: Production and Utilization in Oil Sludge Cleaning. Presented at the SPE EOR Conference at Oil and Gas West Asia held in Muscat, Oman 16 - 18 April 2012. Society of Petroleum Engineers.", "Shibulal, B., Al-Bahry, S. N., Al-Wahaibi, Y. M., Elshafie, A. E., Al-Bemani, A. S. & Joshi, S. J. 2014. Microbial Enhanced Heavy Oil Recovery by the Aid of Inhabitant Spore-Forming Bacteria: An Insight Review. The Scientific World Journal, 2014.", "Nicholson, W. L., Munakata, N., Horneck, G., Melosh, H. J. & Setlow, P. 2000. Resistance of Bacillus endospores to extreme terrestrial and extraterrestrial environments. Microbiology and Molecular Biology Reviews, 64, 548-572.", "Lazar, I., Petrisor, I. & Yen, T. 2007. Microbial enhanced oil recovery (MEOR). Petroleum Science and Technology, 25, 1353-1366.", "Springham, D. G. 1984. Microbiological methods for the enhancement of oil recovery. Biotechnology and genetic engineering reviews, 1, 187-222.", "Bryant, R. S. Potential uses of microorganisms in petroleum recovery technology. Proceedings of the Oklahoma Academy of Science, 1987. 97-104.", "Al-Hattali, R. 2012. Microbial Biomass for Improving Sweep Efficiency in Fractured Carbonate Reservoir Using Date Molasses as Renewable Feed Substrate. SPE Annual Technical Conference and Exhibition, 8-10 October, San Antonio, Texas, USA. Society of Petroleum Engineers.\n[10]\tSen, R. 2008. Biotechnology in petroleum recovery: the microbial EOR. Progress in Energy and Combustion Science, 34, 714-724.\n[11]\tVazquez-Duhalt, R. & Quintero-Ramirez, R. 2004. Biotechnological approach for development of microbial enhanced oil recovery technique. Petroleum Biotechnology: Developments and Perspectives, 151, 405 -445.\n[12]\tAl-Sulaimani, H., Joshi, S., Al-Wahaibi, Y., Al-Bahry, S., Elshafie, A. & Al-Bemani, A. 2011. Microbial biotechnology for enhancing oil recovery: current developments and future prospects. Biotechnol. Bioinf. Bioeng, 1, 147-158.\n[13]\tBanat, I., Franzetti, A., Gandolfi, I., Bestetti, G., Martinotti, M., Fracchia, L., Smyth, T. & Marchant, R. 2010. Microbial biosurfactants production, applications and future potential. Applied Microbiology and Biotechnology, 87, 427-444.\n[14]\tHamouda, A. A. & Karoussi, O. 2008. Effect of temperature, wettability and relative permeability on oil recovery from oil-wet chalk. Energies, 1, 19-34.\n[15]\tMccaffery, F. G. 1972. Measurement of interfacial tensions and contact angles at high temperature and pressure. Journal of Canadian Petroleum Technology, 11.\n[16]\tWang, W. & Gupta, A. Investigation of the effect of temperature and pressure on wettability using modified pendant drop method. SPE Annual Technical Conference and Exhibition, 1995. Society of Petroleum Engineers.\n[17]\tDunlap, C., Schisler, D., Price, N. & Vaughn, S. 2011. Cyclic lipopeptide profile of three Bacillus subtilis strains; antagonists of Fusarium head blight. The Journal of Microbiology, 49, 603-609."]} The increasing high price of natural gas and oil with attendant increase in energy demand on world markets in recent years has stimulated interest in recovering residual oil saturation across the globe. In order to meet the energy security, efforts have been made in developing new technologies of enhancing the recovery of oil and gas, utilizing techniques like CO2 flooding, water injection, hydraulic fracturing, surfactant flooding etc. Surfactant flooding however optimizes production but poses risk to the environment due to their toxic nature. Amongst proven records that have utilized other type of bacterial in producing biosurfactants for enhancing oil recovery, this research uses a technique to combine biosurfactants that will achieve a scale of EOR through lowering interfacial tension/contact angle. In this study, three biosurfactants were produced from three Bacillus species from freeze dried cultures using sucrose 3 % (w/v) as their carbon source. Two of these produced biosurfactants were screened with the TEMCO Pendant Drop Image Analysis for reduction in IFT and contact angle. Interfacial tension was greatly reduced from 56.95 mN.m-1 to 1.41 mN.m-1 when biosurfactants in cell-free culture (Bacillus licheniformis) were used compared to 4. 83mN.m-1 cell-free culture of Bacillus subtilis. As a result, cell-free culture of (Bacillus licheniformis) changes the wettability of the biosurfactant treatment for contact angle measurement to more water-wet as the angle decreased from 130.75o to 65.17o. The influence of microbial treatment on crushed rock samples was also observed by qualitative wettability experiments. Treated samples with biosurfactants remained in the aqueous phase, indicating a water-wet system. These results could prove that biosurfactants can effectively change the chemistry of the wetting conditions against diverse surfaces, providing a desirable condition for efficient oil transport in this way serving as a mechanism for EOR. The environmental friendly effect of biosurfactants applications for industrial purposes play important advantages over chemically synthesized surfactants, with various possible structures, low toxicity, eco-friendly and biodegradability.

As an alternative to the construction of new infrastructure, repurposing existing natural gas pipelines for hydrogen transportation has been identified as a low-cost strategy for substituting natural gas with hydrogen in the wake of the energy transition. In line with that, a 342 km, 36″ natural gas pipeline was used in this study to simulate some technical implications of delivering the same amount of energy with different blends of natural gas and hydrogen, and with 100% hydrogen. Preliminary findings from the study confirmed that a three-fold increase in volumetric flow rate would be required of hydrogen to deliver an equivalent amount of energy as natural gas. The effects of flowing hydrogen at this rate in an existing natural gas pipeline on two flow parameters (the compressibility factor and the velocity gradient) which are crucial to the safety of the pipeline were investigated. The compressibility factor behaviour revealed the presence of a wide range of values as the proportions of hydrogen and natural gas in the blends changed, signifying disparate flow behaviours and consequent varying flow challenges. The velocity profiles showed that hydrogen can be transported in natural gas pipelines via blending with natural gas by up to 40% of hydrogen in the blend without exceeding the erosional velocity limits of the pipeline. However, when the proportion of hydrogen reached 60%, the erosional velocity limit was reached at 290 km, so that beyond this distance, the pipeline would be subject to internal erosion. The use of compressor stations was shown to be effective in remedying this challenge. This study provides more insights into the volumetric and safety considerations of adopting existing natural gas pipelines for the transportation of hydrogen and blends of hydrogen and natural gas.

This investigation was carried out to highlight the influence of the variation of permeability of the porous media with respect to the injection orientations during enhanced gas recovery (EGR) by CO2 injection using different core samples of different petrophysical properties. The laboratory investigation was performed using core flooding technique at 1300 psig and 50 °C. The injection rates were expressed in terms of the interstitial velocities to give an indication of its magnitude and variation based on the petrophysical properties of each core sample tested. Bandera Grey, Grey Berea, and Buff Berea sandstone core samples were used with measured permeabilities of 16.08, 217.04, and 560.63 md, respectively. The dispersion coefficient was observed to increase with a decrease in permeability, with Bandera Grey having the highest dispersion coefficient and invariably higher mixing between the injected CO2 and the nascent CH4. Furthermore, this dispersion was more pronounced in the horizontal injection orientation compared to the vertical orientation with, again, the lowest permeability having a higher dispersion coefficient in the horizontal orientation by about 50%. This study highlights the importance of the permeability variation in the design of the injection strategy of EGR and provides a revision of the CO2 plume propagation at reservoir conditions during injection.

The choice of the flow velocity in EGR thus becomes important since higher injection rates could lead to premature mixing of the fluids and lower injection rates generally provide longer resident times for the fluids in contact and indirectly increases the mixing of the gases. Additionally, the medium peclet numbers mostly indicate the best injection rates that translate to a smoother displacement with a lower dispersion coefficient during the EGR process. Therefore, N2 Injection into natural gas reservoirs offers the potential to higher recovery efficiency with less mixing compared to conventional CO2 injection. The atmospheric air contained 79% of N2, making it readily available than CO2 with 400 ppm air composition. More so, N2 requires less compression ratio, which is why a lower amount of it was required to initiate much pressure in the CH4 reservoir during displacement. These made the use of N2 more economically feasible and friendly for the EGR process. A laboratory core flooding experiment was carried out to simulate the effect of injection velocity on CH4 recovery and dispersion coefficient. This was done at 40 ◦C, 1500 psig, and 0.2–1.0 ml/min injection rates. The results showed that a medium peclet number could be used to predict the best injection rate that translates to a smoother displacement with a lower dispersion coefficient during the EGR process. CH4 recovery and efficiency were highest at lower injection velocities experienced in both core samples. This could be attributed to insignificance nascent mixing observed as seen on their recorded low longitudinal dispersion coefficient results. Consequence, the experimental runs at high injection rates (0.6–1.0 ml/min) present a different scenario with lower recovery and efficiency due to their high interstitial velocities as the N2 plumes transverses into the core sample during CH4 displacement. Overall, the least methane production and efficiency were noticed in the Bandera core sample as a result of the heterogeneity effect due to the presence of higher clay contents in Bandera than Berea gray. When the capillary forces within the narrower pores in Bandera core sample were overcome, the clay particles occupied those pores thereby sealing some of the flow paths within the pore matrix. This reduces the flow channels, significantly, through which the injected N2 will flow to displace the residual CH4.