Viscosity and Stability of Dry CO2 Foams for Improved Oil Recovery

Fig. 1: Foam-stability test in a sapphire cell, (a) upon foam generation at time zero and (b) after 1 day.

Carbon dioxide (CO2)/water foams are of interest for mobility control in CO2 enhanced oil recovery (EOR) and as energized fracture fluids or as hybrid processes that combine aspects of both processes. It is challenging to stabilize ultradry foams with extremely high internal-phase gas fraction given the high capillary pressure and the rapid drainage rate of the lamellae between the gas bubbles. However, the authors demonstrate that these ultradry CO2-in-water foams may be stabilized with surfactants that form viscoelastic worm-like micelles in the aqueous phase.

Introduction

In this study, the authors extend the study of ultradry CO2/water foams composed of worm-like micelles to higher temperatures by adding an electrolyte, potassium chloride (KCl), and a cationic surfactant, decyldimethylamine (C10DMA), to the primary surfactant, sodium lauryl ether sulfate (SLES). The continuous-phase viscosity and surface shear viscosity of this formulation were found to be approximately two orders of magnitude higher when worm-like micelles were formed at room temperature. The foam morphology was measured at high pressure with microscopy, and a long lifetime of foam bubbles was demonstrated. The morphology of the worm-like micelles was also characterized by cryogenic transmission electron microscopy.

The authors have been able to manipulate foam stability for various specialty applications such as EOR where low water consumption, foam stability and extended life span, and conformance of the foams are crucial. In particular, these high-quality stable foams have been developed and tested at laboratory scale in high-salinity and high-temperature conditions to mimic the actual reservoir condition. These high-quality, highly stable foams have been generated and tested by use of sandpacks at the laboratory scale. In this work, a numerical simulation of foam injection into a layered reservoir is performed.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179690, “Viscosity and Stability of Dry CO2 Foams for Improved Oil Recovery,” byChang Da, Zheng Xue, Andrew J. Worthen, Ali Qajar, Chun Huh, Maša Prodanović,and Keith P. Johnston, The University of Texas at Austin, prepared for the 2016 SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. The paper has not been peer reviewed.
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Viscosity and Stability of Dry CO2 Foams for Improved Oil Recovery

10 June 2016

Volume: 68 | Issue: 7

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