Journal of Petroleum & Environmental Biotechnology

Novel surfactants for mobility and conformance control CO₂ foams

International Conference and Expo on Oil and Gas

November 16-18, 2015 Dubai, UAE

Robert Enick1, Hussein Baled1, Guy Biesman2, Luis Salazar2, Huntsman2, Yee Soong2, T Robert McLendon2, Jim Fazio2, Robert Dilmore2, Dustin Crandall2 and Jonathan Moore2

1University of Pittsburgh, USA
2US Department of Energy, USA

Scientific Tracks Abstracts: J Pet Environ Engineering

Abstract:

The low viscosity of high pressure CO2 injection in oil-bearing formations leads to a host of problems including viscous fingering, enhanced gravity override, loss of CO2 to their zones, high produced gas-to-oil ratios, high CO2 utilization rates and high gas re-compression costs. Water-alternating-gas (WAG) flooding remains the standard technique for reducing CO2 mobility via reduction of CO2 relative permeability, while gels can improve conformance control in stratified formations by diverting flow from thief zones. Surfactant-stabilized CO2-in-brine foams (CO2 is the high volume %, internal phase) remain a promising, low-cost means of mobility control and or conformance control. A review of the prior use of nonionic, anionic and cationic surfactants in lab tests and pilot trials will be presented, most notably the alternate injection of aqueous surfactant solution and CO2 gas (SAG). A summary of our recent surfactant design developments will also be presented. Surfactant solubility studies, high pressure foam stability tests, static and dynamic adsorption experiments, flow-through-porous media pressure drop (i.e., mobility) results and CT imaging of foam formation in porous media will be used to illustrate the performance of the surfactants. For example, certain amphoteric surfactants appear to be excellent foaming agents at extreme temperatures (up to ~130o C) when dissolved in high (~250000 ppm) total dissolved solids (TDS) brines such as those found in Middle Eastern formations. With regard to non-ionics, one can employ specific non-ionic surfactants that dissolve appreciably in CO2 but are even more brine-soluble. When a CO2-non-ionic surfactant solution enters the formation, the surfactant will partition into the brine and stabilize the foam, thereby facilitating the continuous injection of a CO2-surfactant solution (GS process) or the alternate injection of brine and a CO2-surfactant solution (WAGS). To gain the greatest assurance that foams are generated in-situ, an operator could also inject surfactant in the brine phase and in the alternating CO2 slugs (SAGS). Finally, we will include an assessment of the CO2-soluble and brine-soluble �??switchable�?� surfactants identified by Johnston and coworkers that exhibit a non-ionic to cationic transformation triggered by the carbonic acid that forms in the brine.

Biography :

Robert Enick is the Professor of the Department of Chemical and Petroleum Engineering at the University of Pittsburgh. He is an ORISE Faculty Fellow at the National Energy Technology Laboratory, where he teams with NETL scientists to study high pressure phase behavior and viscometry related to primary and tertiary oil recovery processes. He also has expertise in improving the performance of CO2 enhanced oil recovery by decreasing its mobility with CO2-soluble thickeners, CO2-soluble foaming agents and brine-soluble surfactants. He also studies the thickening of natural gas liquids for improved hydrocarbon miscible displacement.

Email: rme@pitt.edu