Thermal recovery processes, and in particular, Steam-assisted gravity drainage (SAGD), are the most common and practical in situ technology for bitumen extraction. While SAGD is effective, steam injection results in poor steam chamber growth and distribution with poor conformance specifically in areas with poor formation geology and bedding properties. These factors result in economic and environmental costs. Co-injecting foaming surfactants with noncondensable gases along with steam is an alternative solution to control the steam chamber behavior and its advancement throughout the formation. Selecting appropriate foaming surfactants is essential for successful implementation of a foam-steam processes. Conventional laboratory methods provide some indication of foaming surfactant performance but fail to reflect reservoir conditions and time scales. Microfluidics is well suited to assess the relevant pore-scale performance of foaming surfactants, at relevant conditions, with tight control over experimental parameters. Here, we develop a microfluidic approach to generate nitrogen-foam and assess stability and mobility control performance at relevant temperature (>150 °C) with results compared to those of traditional bulk foam analysis. The microconfinement associated with porous media creates more stable foam at reservoir-relevant temperatures and pressures. Direct visualization of the foaming dynamics, subsequent stability, and mobility testing in porous media provide a rapid assessment of foam performance as well as a diagnostic of surfactant product failures such as precipitation and phase decomposition, findings that directly informed pilot operations here. This screening also enables down-selection of the most promising agents for subsequent testing with candidate reservoir oil, in conventional cores or micromodels.

This paper reports p–ρ–T (pressure, mass density, temperature) data measured for a mixture with molar composition (0.95039 methane + 0.03961 ethane + 0.01000 propane) using a high-pressure, single-sinker, magnetic-suspension densimeter (MSD) and high- and low-pressure automated isochoric apparatus at temperatures from (135 to 500) K and pressures to 200 MPa. The composition is representative of a residual natural gas in pipelines, but the range of conditions covers conditions possibly encountered in production and processing. The k = 2 relative uncertainty for the density measurements using the MSD is 5 × 10–4 ·ρ based upon an uncertainty analysis for the instrument. The isothermal densities measured in the MSD in combination with the low- and high-pressure isochoric data determine additional density data with essentially the same estimated relative uncertainty as the MSD in the high temperature range (above 300 K) and a relative uncertainty of 3 × 10–3 ·ρ at lower temperatures. The measured densities range from (433.170 to 27.493) kg·m–3. The GERG-2008 equation of state compares well to the density data. Although the data behave in an expected manner, they cover ranges of temperature and pressure beyond those previously examined. Additionally, the paper describes a new, high-pressure isochoric apparatus as well as a methodology for compensating volume changes and the mass interchanges in the high-pressure cell. The latter technique allows experimental determination of the cell distortion coefficients.