Gelled Emulsions of CO2, Water, and Nanoparticles
- Chris Carpenter (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 2014
- Document Type
- Journal Paper
- 135 - 137
- 2014. Society of Petroleum Engineers
- 1 in the last 30 days
- 271 since 2007
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166072, "Gelled Emulsions of CO2/Water/Nanoparticles," by Fawaz M. Al-Otaibi, Sunil L. Kokal, Yun C. Chang, Jassi F. Al-Qahtani, and Amin M. Al-Abdulwahab, Saudi Aramco, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed.
Enhanced oil recovery (EOR) by carbon dioxide (CO2) injection is an effective method for recovering additional oil beyond waterflooding. However, the CO2-EOR process is handicapped, especially in thick reservoirs, by CO2 gravity override. Because of density differences between the injected CO2 and resident fluids in the reservoir, the lighter CO2 tends to rise to the top of the reservoir, thereby bypassing some of the remaining oil. This paper investigates the use of gelling CO2/water emulsions, stabilized by silica nanoparticles, to control the mobility of CO2.
The CO2-EOR process, while increasingly important, is handicapped by several challenges. The first challenge is the gravity override of the injected CO2 because of density differences between the injected CO2 and resident fluids in the reservoir. The second is viscous fingering caused by the lower viscosity of the injected CO2. Typical dense CO2 viscosity at reservoir conditions is in the range of 0.05–0.1 cp, which is much lower than the viscosity of resident oil and brine. The resulting unfavorable mobility ratio leads to viscous fingering, causing early CO2 breakthrough, high CO2-usage factors, poor sweep efficiency, and low overall oil recovery. The third challenge associated with CO2 EOR is reservoir geology and heterogeneities, including high-permeability streaks and fractures that can impact the sweep efficiency of a CO2-EOR flood. Most of these challenges have been countered by use of water-alternating-gas (WAG) processes. Although the WAG process improves the mobility of CO2, it loses its effectiveness in controlling CO2 mobility deep into the reservoir and beyond a certain distance from the wellbore.
This paper discusses another technique that provides an excellent alternative to WAG to control CO2 mobility: the CO2/foam emulsion. The main purpose of using CO2 foams is to increase the viscosity of the CO2 and therefore reduce its mobility through the reservoir. This emulsion is generated with water-soluble surfactants, CO2-soluble surfactants, or nanoparticles. This paper investigates the use of gelling CO2/water emulsions, stabilized by silica nanoparticles, to control the mobility of CO2.
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