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.

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%.

Alkaline-Surfactant-Foam flooding is a novel enhanced oil recovery process which increases oil recovery over water flooding by combining lowering of the oil-water interfacial tension by two to three orders of magnitude and foaming. We report an experimental study of the formation of the oil bank and its displacement by foam drives of varying qualities. Experiments include: (a) bulk phase behaviour and foam testing studies using n-hexadecane and a single internal olefin sulfonate surfactant which was found to lower the oil-water interfacial tension by at least two orders of magnitude and (b) series of CT scanned core-floods using Bentheimer sandstone cores. A major goal of this study was to investigate the effect of drive foam quality on oil bank displacement. Core-flood results, performed at under-optimum salinity conditions yielding an oil-water interfacial tension in the order of 10−1 mN/m, showed similar ultimate oil recovery factors for the range of drive foam qualities studied. Although the total oil recovery is not affected by drive foam quality, results indicate a more frontal oil bank displacement at lower foam qualities. The findings in this study suggest that a) a lower drive foam quality favours oil bank displacement and b) the amount of clean oil produced by the oil bank is not effected by drive foam quality.

The novel enhanced oil recovery (EOR) technique combining the reduction of oil/water (o/w) interfacial tensions (IFT) to ultralow values and generation of a foam drive for mobility control is known as foam-assisted chemical flooding (FACF). We present a well-controlled laboratory study on the feasibility of FACF at reservoir conditions. Two specially selected chemical surfactants were screened on their stability in sea water at 90 °C. The ability of both surfactants to generate stable foam in bulk was studied in the presence and absence of crude oil. It led to the composition of the foam drive formulation for drive mobility control. Phase behavior scan studies, for the two crude oil/surfactant/brine systems, yielded the design of the chemical slug capable of mobilizing residual oil by drastically lowering the o/w IFT. Core-flood experiments were performed in Bentheimer sandstones previously brought to a residual oil to waterflood of 0.33 ± 0.02. A surfactant slug at under-optimum (o/w IFT of 10 −2 mN/m) or optimum (o/w IFT of 10 −3 mN/m) salinity was injected for mobilizing residual oil. It resulted in the formation of an unstable oil bank because of dominant gravitational forces at both salinities. Next, a foam drive was generated either in situ, by co-injecting nitrogen gas and surfactant solution, or pregenerated ex situ and then injected to displace the oil bank. We found that (i) the presence of the crude oil used in this work has a detrimental effect on foam stability in bulk and foam strength in Bentheimer sandstones, (ii) optimum salinity FACF was able to increase the ultimate oil recovery with 5% of the oil in place (OIP) after water flooding compared with under-optimum FACF, and (iii) injection of pregenerated drive foam increased its ultimate oil recovery by 13% of the OIP after water flooding compared to in situ drive foam generation at optimum salinity.

As part of a seismic monitoring project in a geothermal field, where the feasibility of re-injection and storage of produced CO2 is being investigated, a P- and S-wave seismic velocity characterisation study was carried out. The effect of axial (up to 95 MPa) and radial (up to 60 MPa) stress on the seismic velocity was studied in the laboratory for a broad range of dry sedimentary and metamorphic rocks that make up the Kızıldere geothermal system in Turkey. Thin section texture analyses conducted on the main reservoir formations, i.e., marble and calcschist, confirm the importance of the presence of fractures in the reservoir: 2D permeability increases roughly by a factor 10 when fractures are present. Controlled acoustic-assisted unconfined and confined compressive strength experiments revealed the stress-dependence of seismic velocities related to the several rock formations. For each test performed, a sharp increase in velocity was observed at relatively low absolute stress levels, as a result of the closure of microcracks, yielding an increased mineral-to-mineral contact area, thus velocity. A change in radial stress appeared to have a negligible impact on the resulting P-wave velocity, as long as it exceeds atmospheric pressure. The bulk of the rock formations studied showed reducing P-wave velocities as function of increasing temperature due to thermal expansion of the constituting minerals. This effect was most profound for the marble and calcschist samples investigated.