Selective hydrogenation of carboxylic acids to alcohols and alkanes has been achieved under remarkably mild reaction temperatures and H(2) pressures (333 K, 0.5 MPa) using Pt/TiO(2) catalyst.

A laboratory study of principal immiscible gas flooding schemes is reported. Very well controlled experiments on continuous gas injection, Water-Alternating-Gas (WAG) and Alkaline-Surfactant-Foam (ASF) flooding were conducted. The merits of WAG and ASF compared to continuous gas injection were examined. The impact of ultra-low oil-water (o/w) interfacial tension (IFT), an essential feature of the ASF scheme along with foaming, on oil mobilisation and displacement of residual oil to waterflood was also assessed. Incremental oil recoveries and related displacement mechanisms by ASF and WAG compared to continuous gas injection were investigated by conducting CT scanned core-flood experiments using n-hexadecane and Bentheimer sandstone cores. Ultimate oil recoveries for WAG and ASF at under-optimum salinity (o/w IFT of 10-1 mN/m) were found to be similar (60±5% of the oil initially in place (OIIP)). However, ultimate oil recovery for ASF at (near-)optimum salinity (o/w IFT of 10-2 mN/m) reached 74±8% of the OIIP. Results support the idea that WAG increases oil recovery over continuous gas injection by drastically increasing the trapped gas saturation at the end of the first few WAG cycles. ASF flooding was able to enhance oil recovery over WAG by effectively lowering o/w IFT (<10-1 mN/m) for oil mobilisation. ASF at (near-)optimum salinity increased clean oil fraction in the production stream over under-optimum salinity ASF.

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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%.