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A Comparative Study of Gas Flooding and Foam-Assisted Chemical Flooding in Bentheimer Sandstones


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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This study is the result of collaboration between Delft University of Technology, Universiti Teknologi Petronas, Petronas and Shell. We are grateful to Petronas and Shell for funding the project. The authors thank Petronas for the supply of materials and data.

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Correspondence to Martijn T. G. Janssen.

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Appendix A: Pressure Drop Versus Oil Bank Shape During AS Slug Injection

Appendix A: Pressure Drop Versus Oil Bank Shape During AS Slug Injection

In order to study the relationship between the observed pressure drops (Fig. 6) and corresponding shapes of the oil bank (Fig. 7) Darcy’s law, in combination with Brooks and Corey model for relative permeabilities (Brooks and Corey 1966), was applied to simple test cases presented in Table 10 and Fig. 17. The formulas used are shown below. A simplified one dimensional Darcy’s law was assumed:

$$ \Delta P = {u_{\text{tot}}}\left( {\frac{{{f_{\text{o}}}{\mu_{\text{o}}}}}{{{k_{\text{ro}}}k}} + \frac{{{f_{\text{w}}}{\mu_{\text{w}}}}}{{{k_{\text{rw}}}k}}} \right)L $$

where ΔP, utot, μa, \( \;{k_{\text{ra}}} \), k, fa and L represent the pressure drop, total superficial velocity, viscosity of phase a, relative permeability of phase a, absolute permeability to brine, fractional flow of phase a and the core length, respectively. Subscripts o and w refer to the oil and water phases, respectively. The relative permeabilities are derived using Brooks and Corey model:

$$ {k_{\text{ro}}} = {k_{{\text{r}}{{\text{o}}^*}}}{\left( {\frac{{{S_{\text{o}}} - {S_{\text{or}}}}}{{1 - {S_{\text{or}}} - {S_{\text{wc}}}}}} \right)^{{n_{\text{o}}}}} $$
$$ {k_{\text{rw}}} = {k_{{\text{r}}{{\text{w}}^*}}}{\left( {\frac{{{S_{\text{w}}} - {S_{\text{wc}}}}}{{1 - {S_{\text{or}}} - {S_{\text{wc}}}}}} \right)^{{n_{\text{w}}}}} $$

where \( {k_{{\text{r}}{{\text{a}}^*}}} \) and na represent the end-point relative permeability and the Brooks–Corey exponent for phase a, respectively. Pressure drops are derived using a space interval of 1.0 cm (i.e. for every cm pressure drops are calculated using the saturation distributions presented in Fig. 17). Note that we only address the variations in phase saturations, i.e. relative permeabilities, and its impact on the total pressure drop.

Table 10 Parameters used to derive the pressure drop analytically for the two model cases shown in Fig. 17
Fig. 17

Simplified test cases that represent the development of the oil bank during AS slug injection at, respectively, under-optimum (left) and (near-)optimum (right) salinity conditions. Note that the development of the oil bank in the model has similar characteristics as the observations made during the performed experiments (Fig. 7). Water saturations were calculated using 1 − So. The total amount of oil present at each time was held constant; assuming no oil being produced

The derived total pressure drop profiles, i.e. the sum of pressure drops calculated over 1.0 cm sections, are shown in Fig. 18. Qualitatively they are similar to the observed pressure drops during AS slug injection in the experiments conducted (Fig. 6): a sharp increase followed by a more gradual increase (under-optimum) and a sharp increase followed by a gradual decrease [(near-)optimum]. The higher pressure drops during under-optimum compared to (near-)optimum injection is due to the relatively high peak So (close to 1 − Swc) within the oil bank. The reduction in water mobility, \( \frac{{{k_{\text{rw}}}k}}{{{\mu_{\text{w}}}}} \), has the greatest impact on the increase in pressure drop. Furthermore, as injection continued at under-optimum salinity conditions, the oil bank grew continuously while maintaining its peak So, thus enlarging the total pressure drop.

At (near-)optimum salinity injection first a sharp increase in pressure drop is seen due to the formation of the sharp oil bank at early injection times (similar to under-optimum salinity injection). Afterwards, peak So reduced and the oil bank became more uniform. The constant, relatively low, So of around 0.5 revealed a slight reduction in total pressure drop as the peak So within the oil bank was reduced significantly. This effect could not be compensated by the growth of the oil bank. Further development of the oil bank hardly effects the pressure drop as the expansion at the leading edge is neutralised by a slight reduction in peak So.

Fig. 18

Total pressure drop profiles constructed for the two simplified models shown in Fig. 17. Note that qualitatively it represents the observations made during AS slug injection in Exp. 4 and 5

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Janssen, M.T.G., Pilus, R.M. & Zitha, P.L.J. A Comparative Study of Gas Flooding and Foam-Assisted Chemical Flooding in Bentheimer Sandstones. Transp Porous Med 131, 101–134 (2020). https://doi.org/10.1007/s11242-018-01225-3

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  • Alkaline
  • Surfactant
  • Foam
  • Oil
  • Immiscible gas injection
  • Water-alternating-gas
  • Enhanced oil recovery