Surfactant flooding is an enhanced oil recovery method that recovers residual and capillary trapped oil by improving pore-scale displacement efficiency. Low retention of injected chemicals is desired to ensure an economic and cost-effective recovery process. This paper examines the adsorption behavior of a novel gemini cationic surfactant on carbonate cores. The rock cores were characterized using an X-ray diffraction (XRD) spectroscope. In addition, the influence of critical parameters on the dynamic adsorption of the cationic gemini surfactant was studied by injecting the surfactant solution through carbonate cores in a core flooding apparatus until an equilibrium state was achieved. The concentration of surfactant was observed using high performance liquid chromatography. Experimental results showed that an increasing surfactant concentration causes higher retention of the surfactant. Moreover, increasing the flow rate to 0.2 mL/min results in lowering the surfactant retention percentage to 17%. At typical high salinity and high temperature conditions, the cationic gemini surfactant demonstrated low retention (0.42 mg/g-rock) on an Indiana limestone core. This study extends the frontier of knowledge in gemini surfactant applications for enhanced oil recovery.
Hydration of shale formations during drilling operations have adverse effects on wellbore stability. The shale hydration resulted from the interactions between drilling fluid and swelling clay contents in the shale formations. This paper addresses the improvement of wettability and hydration properties of shale to enhance the wellbore stability during the drilling operations. The novel ionic liquid-based drilling fluids were used to alter the wettability and hydration properties of shale. The novel ionic liquid based drilling fluid was developed by blending various ionic liquids and drilling fluid additives such as filtration control agent and rheological modifier. The rheology and filtration related properties of the base drilling fluid and its modified version with ionic liquids were determined. Shale inhibition characteristics of modified drilling fluids were evaluated by using real field shale sample and analyzing it with linear shale swelling test and hot rolling dispersion test. Two different ionic liquids (IL-1, IL-2) were deployed in the formulation of drilling fluids with a concentration of 0.05%. The conventionally used shale inhibitor KCl was also used in the formulation of drilling fluid with the concentration of up to 2%. The results of modified drilling fluids were then compared with the base drilling fluids prepared by mixing bentonite and cationic polymer (polydadmac). The rheological experiments showed that the addition of KCl and ionic liquids in the base drilling fluid resulted in a decrease in rheological properties. The filtration experiments also showed that filtrate volume has increased with the addition of KCl and ionic liquids in the drilling fluids. The hot rolling shale recovery experiment was performed at 65°C and superior shale recovery was observed with the synergistic effect of B/IL-2/K drilling fluid. Linear swelling of shale was assessed over a time period of 10 hours and minimum linear swelling of shale was observed with B/IL-2/K drilling fluid which indicated that the ionic liquid in the drilling fluid chemically interacts with the shale surface and makes it hydrophobic in nature which limits the interactions of water with shale. This use of novel ionic liquid-based drilling fluid enhances the borehole stability by modifying the shale surface and resulted in improved wellbore stability. The novel drilling fluid also has superior rheological, filtration properties and salt tolerance.
After water flooding in carbonate reservoirs, a significant fraction of the original oil as remaining oil is left in the swept zone. The remaining oil in the pore, trapped by viscous and capillary forces, is to target for improved and enhanced oil recovery. The mobilization of remaining oil can be predicted by a dimensionless parameter called capillary number. The interfacial tension and injection flow rate strongly affect the capillary number. Unfortunately, the interrelationship between capillary number, interfacial tension, injection flow rate, and the temperature has been poorly studied for carbonate reservoirs. This paper focuses on studying the remaining oil saturations at different orders of magnitude capillary numbers related to interfacial tension, injection flow rate, and temperature by seawater and surfactant flooding. Several core flooding experiments were performed by changing the injection rate and surfactant concentrations at evaluated conditions. Four displacement experiments of seawater/oil and surfactant solution/oil were performed using oil-wet carbonate cores to obtain the relationship between the residual oil saturation vs. the capillary number. The surfactant flooding experiments with different concentrations of 0.01 and 0.2 wt% were conducted when the remaining oil saturation was reached after water flooding. Three core flooding experiments were conducted at ambient conditions, and one was under evaluated conditions of a temperature of 100° and pore pressure of 3200 psi. Several injection rates were selected to experiment with a 0.2 wt% surfactant solution, which is to study the effect of injection rate on the capillary number and residual oil saturation. The experimental findings show that some remaining oil can be recovered from oil-wet carbonate cores if the capillary number increases by a critical Nc =2.1E-05 by surfactant flooding at reservoir conditions. After water flooding, the remaining oil saturation was decreased from 51% to 16% with 0.01wt% surfactant flooding. The reduction of interfacial tension from 6.77dyne/cm to 0.017dyne/cm led to an increased capillary number. It decreased the remaining oil saturation by about 5% OOIP when the capillary number increases three magnitudes. The effect of temperature and injection rate on the capillary number was observed based on experimental displacement results. Compared with results between the ambient and specified conditions, the effect of temperature on the capillary number is significant. Under the same capillary number, the remaining oil recovered by surfactant flooding at HPHT conditions was higher than that at ambient conditions. Also, the effect of the injection flow rate on the capillary number was observed by 0.2wt % surfactant flooding for all experiments. The capillary number increased with an increase in the injection rate for both ambient and evaluated conditions. This paper provides valuable results to evaluate the interrelationship between remaining oil and capillary numbers by surfactant flooding and design field application for oil-wet carbonate reservoirs.
The release of CO2 into the atmosphere has been verified as a significant reason for global warming and climate change. To prevent a large amount of CO2 from being emitted into the atmosphere, its utilization and storage become very important for human survival. Regarding the utilization of CO2 in oil reservoir engineering practice, CO2 enhanced oil recovery (CO2EOR) as a mature technology has been widely applied in several types of reservoirs, such as sandstone, carbonate, and shale gas/oil reservoirs, and scientists and reservoir engineers aim to improve displacement efficiency with different injection modes and study its influencing factors over the past few decades. However, related to the experimental evaluation of storage capacity potential with the CO2EOR displacement mode and the long-term storage of CO2 in situ in the formation experienced by CO2 flooding is rarely studied experimentally. In this study, we investigated the effect of injection mode and reservoir heterogeneity on CO2EOR and its storage potential. Several core flooding experiments on displacing remaining oil and water by scCO2 after water flooding have been performed, including injection modes, which are horizontal, vertical, and tapered WAG injections, using reservoir carbonate rock, live crude oil, and seawater under reservoir conditions. The dual-core core flooding experiment was used to study the effect of reservoir heterogeneity on scCO2 storage capacity. As a result of this study, the previously proposed experimental methodology was used to calculate the scCO2 storage capacity, which involved that the scCO2 dissolves into residual water and oil after scCO2 injection, and evaluate the CO2 storage capacity efficiency for different injection modes. The vertical-continuous injection mode of scCO2 flooding can maximize the process of its storage advantage. This study found that the main scCO2 storage mechanism is mainly pore storage (structural trapping) for depleted oil reservoirs. Based on experimental results, the storage efficiency is related permeability of rocks, which expresses the logarithmic relation and increases with an increase in air permeability. The experimental results show that the scCO2 injectivity is not strongly affected, although the relative permeability to scCO2 decreased somewhat after the scCO2EOR process. In addition, the effect of rock heterogeneity on scCO2 storage efficiency is also discussed. The highlights of this study are that the comparison of the scCO2 storage potential was made based on experimental results of different injection modes, and improving the displacement efficiency in the low permeable zone also increases scCO2 storage efficiency. Furthermore, the experimental results can be applied directly to be helpful for the evaluation and strategy of scCO2 storage and can be used to simulate the performance during the injection process of scCO2 storage.
To reduce the amount of CO2 in the atmosphere and mitigate the severe consequences of climate change, capturing, utilizing, and storing CO2 has become very important for human survival. For utilization of CO2 in reservoir engineering practice, CO2-enhanced oil recovery (CO2EOR) as a mature technology has been widely applied in several types of reservoirs such as sandstone, carbonate, and shale gas/oil reservoirs, and the focus of concern is to study oil recovery efficiency and its influencing factors over the past few decades. Recently, more and more researchers are paying great attention to the geological storage of carbon dioxide in depleted oil reservoirs where scCO2 is injected as a displacing agent for secondary and tertiary oil recovery. Unfortunately, there is a lack of laboratory research on scCO2 sequestration in such reservoirs in terms of capacity, two-phase flow (the mixture of scCO2 and residual oil and water), injectivity of scCO2, and permeability loss of rocks. In this study, we evaluate the dynamic characteristics mentioned above subjective is based on laboratory results. Several experiments, including different injection modes such as horizontal and vertical injections, and their effects on displacing residual oil and water by scCO2 after water flooding has been performed using reservoir carbonate rock, live crude oil, and seawater under reservoir conditions. As a result of this study, the experimental methodology to obtain the scCO2 storage capacity of the depleted oil reservoir was proposed for the first time, and the calculation of scCO2 storage capacity assumes that the scCO2 dissolves into residual water and oil after scCO2 injection. This study found that the main scCO2 storage mechanism is pore space storage (structural trapping) for depleted oil reservoirs. Based on experimental results, the storage efficiency is found to be closely related to the permeability of rocks. In addition, the scCO2 injectivity and permeability loss of the rock were evaluated for a depleted carbonate reservoir, which was displaced by scCO2 injection at the final stage of the oil recovery process. The experimental results show that the scCO2 injectivity is not strongly affected, although the relative permeability to scCO2 slightly decreased after the scCO2EOR process. The experimental results can be applied directly for the evaluation and strategy of scCO2 storage and can be used to simulate the performance of the injection process of scCO2 storage.
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