This article assesses the gasification behavior of sawdust using steam as the gasification agent. To do this, a comprehensive model of biomass gasification consisting of four main processes (biomass dehydration, biomass devolatilization, tar combustion, and char gasification) was developed using an Aspen Plus simulator. Two gasification processes were studied: steam-gasification with primary tar combustion (SIM I) and steam-gasification with no pretreatment (SIM II). The effects of the gasification temperature (650−800 °C) and the steam-to-biomass ratio, S/B (1.1−1.8), on the produced gas composition, gas yield, tar yield, the higher heating value of the syngas (HHV gas ), H 2 /CO, carbon conversion efficiency (CCE), and cold gas efficiency (CGE) were investigated. It was found that the gasification strategy had little effect on the CCE but had a significant effect on the produced gas composition and CGE. During steam-gasification with primary tar combustion (SIM I), HHV gas and H 2 /CO showed higher values, while the tar yield showed lower values. The simulation results also confirmed an insignificant effect of the gasification temperature in the range of 650−800 °C on HHV gas . Regardless of the gasification strategy, it was found that steam-gasification of sawdust achieved the acceptable level of H 2 /CO and HHV gas at simulated conditions and can be considered as an alternative route for the Fischer−Tropsch synthesis.
As foams are not thermodynamically stable and might be collapsed, foam stability is defined by interfacial properties and bulk solution. In this paper, we investigated foam injection and different salinity brines such as NaCl, CaCl2, KCl, and MgCl2 to measure cumulative oil production. According to the results of this experiment, it is concluded that sequential low-salinity water injections with KCl and foam flooding have provided the highest cumulative oil production in sandstone reservoirs. This issue is related to high wettability changes that had been caused by the KCl. As K+ is a monovalent cation, KCl has the highest wettability changes compared to other saline brines and formation water at 1000 ppm, which is due to the higher wettability changes of potassium (K+) over other saline ions. The interfacial tension for KCl at the lowest value is 1000 ppm and, for MgCl2, has the highest value in this concentration. Moreover, the formation brine, regarding its high value of salty components, had provided lower cumulative oil production before and after foam injection as it had mobilized more in the high permeable zones and, therefore, large volumes of oil would be trapped in the small permeable zones. This was caused by the low wettability alteration of the formation brine. Thereby, formation water flowed in large pores and the oil phase remained in small pores and channels. On the other hand, as foams played a significant role in the mobility control and sweep efficiency, at 2 pore volume, foam increased the pressure drop dramatically after brine injection. Consequently, foam injection after KCl brine injection had the maximum oil recovery factor of 63.14%. MgCl2 and formation brine had 41.21% and 36.51% oil recovery factor.
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