scholarly journals Supercritical CO2-involved water–rock interactions at 85℃ and partial pressures of 10–20 MPa: Sequestration and enhanced oil recovery

2017 ◽  
Vol 35 (2) ◽  
pp. 237-258 ◽  
Author(s):  
Xiaoyu Wang ◽  
Xiaolin Wang ◽  
Wenxuan Hu ◽  
Ye Wan ◽  
Jian Cao ◽  
...  

Studying the interactions between CO2-rich fluid and reservoir rock under reservoir temperature and pressure is important for investigating CO2 sequestration and the CO2-enhanced oil recovery processes. Using high-concentration CaCl2-type formation water as an example, this study performed a CO2-rich fluid–rock interaction experiment at 85℃ and compared the dissolution of calcite and sandstone samples, as well as sandstone powder and thin-slice samples. This study also investigated the effects of the sample surface area, the CO2 partial pressure ( PCO2 = 10 and 20 MPa), and the composition of formation water (3 mol/kg NaCl and 1 mol/kg CaCl2–2 mol/kg NaCl) on the water–rock interaction mechanism and process by weighing, ion chromatography, and scanning electron microscopy observations. The results showed that the injection of CO2 resulted in the dissolution of reservoir minerals such as carbonate cements and feldspar. The mineral dissolution increased with increasing PCO2. The dissolution of minerals such as calcite in the CaCl2-type formation water was significantly decreased because of the high concentration of Ca2+. Under the same conditions, more sandstone dissolved than calcite and more sandstone powder dissolved than sandstone thin slices. Dissolution of the potassium feldspar occurred in the sandstone, whereas the albite was nearly unaffected. No new minerals formed during the experimental process. The experimental results and a PHREEQC calculation demonstrated that the injection of CO2 causes a significant pH drop in the formation water, which improves the porosity and permeability of the reservoir, increases the capacity of the reservoir to store CO2, and facilitates the progression of the CO2-enhanced oil recovery process. However, if alkaline minerals in the caprocks of the reservoir are also dissolved by the CO2-rich fluid, the sealing capacity of the caprocks may be reduced.

2021 ◽  
Author(s):  
Tinuola Udoh

Abstract In this paper, the enhanced oil recovery potential of the application of nanoparticles in Niger Delta water-wet reservoir rock was investigated. Core flooding experiments were conducted on the sandstone core samples at 25 °C with the applications of nanoparticles in secondary and tertiary injection modes. The oil production during flooding was used to evaluate the enhanced oil recovery potential of the nanoparticles in the reservoir rock. The results of the study showed that the application of nanoparticles in tertiary mode after the secondary formation brine flooding increased oil production by 16.19% OIIP. Also, a comparison between the oil recoveries from secondary formation brine and nanoparticles flooding showed that higher oil recovery of 81% OIIP was made with secondary nanoparticles flooding against 57% OIIP made with formation brine flooding. Finally, better oil recovery of 7.67% OIIP was achieved with secondary application of nanoparticles relative to the tertiary application of formation brine and nanoparticles flooding. The results of this study are significant for the design of the application of nanoparticles in Niger Delta reservoirs.


Author(s):  
Muhammad Khan Memon ◽  
Ubedullah Ansari ◽  
Habib U Zaman Memon

In the surfactant alternating gas injection, the injected surfactant slug is remained several days under reservoir temperature and salinity conditions. As reservoir temperature is always greater than surface temperature. Therefore, thermal stability of selected surfactants use in the oil industry is almost important for achieving their long-term efficiency. The study deals with the screening of individual and blended surfactants for the applications of enhanced oil recovery that control the gas mobility during the surfactant alternating gas injection. The objective is to check the surfactant compatibility in the presence of formation water under reservoir temperature of 90oC and 120oC. The effects of temperature and salinity on used surfactant solutions were investigated. Anionic surfactant Alpha Olefin Sulfonate (AOSC14-16) and Internal Olefin Sulfonate (IOSC15-18) were selected as primary surfactants. Thermal stability test of AOSC14-16 with different formation water salinity was tested at 90oC and 120oC. Experimental result shows that, no precipitation was observed by surfactant AOSC14-16 when tested with different salinity at 90oC and 120oC. Addition of amphoteric surfactant Lauramidopropylamide Oxide (LMDO) with AOSC14-16 improves the stability in the high percentage of salinity at same temperature, whereas, the surfactant blend of IOSC15-18 and Alcohol Aloxy Sulphate (AAS) was resulted unstable. The solubility and chemical stability at high temperature and high salinity condition is improved by the blend of AOSC14-16+LMDO surfactant solution. This blend of surfactant solution will help for generating stable foam for gas mobility control in the methods of chemical Enhanced Oil Recovery (EOR).


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