Oil Recovery by Alkaline/Surfactant/Foam Flooding: Effect of Drive-Foam Quality on Oil-Bank Propagation

Abstract

Summary Alkaline/surfactant/foam (ASF) flooding is a novel enhanced–oil–recovery (EOR) process that increases oil recovery over waterflooding by combining foaming with a decrease in the oil/water interfacial tension (IFT) by two to three orders of magnitude. We conducted an experimental study regarding the formation of an oil bank and its displacement by foam drives with foam qualities within the range of 57 to 97%. The experiments included bulk phase behavior tests using n–hexadecane and a single internal olefin sulfonate surfactant, and a series of computed–tomography (CT) –scanned coreflood experiments using Bentheimer Sandstone cores. The main goal of this study was to investigate the effect of drive–foam quality on oil–bank displacement. The surfactant formulation was found to lower the oil/water IFT by at least two orders of magnitude. Coreflood results, at under-optimum salinity conditions yielding an oil/water IFT on the order of 10–1 mN/m, showed similar ultimate–oil–recovery factors for the range of drive–foam qualities studied. A more distinct frontal oil–bank displacement was observed at lower drive–foam qualities investigated, yielding an increased oil–production rate. The findings in this study suggested that dispersive characteristics at the leading edge of the generated oil bank in this work were strongly related to the surfactant slug size used, the lowest drive–foam quality assessed yielded the highest apparent foam viscosity (and, thus, the most stable oil–bank displacement), and drive–foam strength increased upon touching the oil bank when using drive–foam qualities of 57 and 77%.

Mechanistic Modeling of Water-Alternating-Gas Injection and Foam-Assisted Chemical Flooding for Enhanced Oil Recovery

“…44 Eventually, an initial oil saturation (S oi ) of 0.76 ± 0.03 was reached in the simulation, which is very similar to the measured S oi of 0.78 ± 0.04. 26 Note that the simulated positions of the displacement fronts (0.30 and 0.52 PV) are located somewhat more downstream compared to our observations. The latter yielded an oil breakthrough time of 0.71 PV, 0.04 ± 0.02 PV earlier compared to experimental data.…”

“…The exact same behavior in pressure drop was seen during waterflooding. Note that flow rates were varied at the end of each injection stage 9,26 to estimate k ro 0 and k rw 0 . Figure 5 presents the simulated and processed oil saturation (S o ) profiles as a function of distance from the inlet for both primary drainage and waterflooding in simulation 3.…”

“…An S or_WF of 0.40 ± 0.01 was reached in the simulation, which corresponds well with the measured one of 0.41 ± 0.02. 26 The results presented in Figures 4 and 5 were obtained by using variable porosity and permeability values as a function of location in space (Section 3.2). When compared with using one fixed value for porosity and permeability for all locations in space, no major differences in terms of pressure drop and saturation profiles were observed.…”

“…26 Simulations 3−5 represent experiments ASF1−ASF3 in our earlier published material. 26 Information on the chemicals, sandstone samples, and experimental setup and procedure is described in detail elsewhere. 26 More specifics on where the abovementioned information can be obtained are shown in Table 1.…”

“…Moreover, the ultimate oil recovery could be increased with 15 ± 5% of the oil initially in place (OIIP) when conducting FACF at (near-)optimum salinity conditions instead of under-optimum salinity. 9 Note that the terminology used in our earlier work 9,26 differs from the terminology used here [alkaline−surfactant−foam (ASF) flooding is identical to FACF].…”