Coreflooding experiments on aged Berea sandstone cores were performed to study the effect of divalent cations on the low-salinity-surfactant enhanced oil recovery (EOR). In the experiments where the core samples were aged for 4 weeks, replacement of a small amount of sodium with calcium in the injected low-salinity surfactant did not lead to higher tertiary recovery. However, the effects on wettability alteration and relative permeabilities were substantial. For the experiments with longer aging duration of 7 weeks, addition of calcium to the injected low salinity surfactant led to better oil recovery and the impact on wettability alteration was strong. Further addition of calcium led to lower oil recovery. Results of the injection experiments were discussed based on interfacial tension (IFT), surfactant adsorption, end-point relative permeabilities, and contact angles. A part of discussion was also dedicated to the effect of calcium on the secondary low-salinity water (LSW) injection. Although the oil recoveries by LSW injection in the absence and presence of calcium are similar, calcium causes late oil mobilization during low-rate LSW injection.

The enhanced oil recovery (EOR) potential of different alkylbenzenesulfonate surfactants was investigated in a combined study of crude oil−water phase behavior and interfacial tension (IFT) and macroscopic oil displacement studies. In the presence of small amounts of calcium ions (calcium/sodium = 4 mol %), ultralow oil−brine IFT (<0.001 mN/m) was observed at ionic strengths 10 times lower than "optimal salinity" with sodium chloride only; this suggested an application in low salinity surfactant (LSS) EOR. "Optimal ionic strength" was determined for different calcium/sodium ratios in the brine, which further allowed prediction of phase behavior and IFT range for a given surfactant and a given crude oil at different brine compositions. In laboratory core floods, crude oil displacement by LSS with an optimal ionic strength electrolyte was around 9% higher than at "non-optimal" conditions.

In integral geometry, intrinsic volumes are a set of geometrical variables to characterize spatial structures, for example, distribution of fluids in two‐fluid flow in porous media. McClure et al. (2018, https://doi.org/10.1103/PhysRevFluids.3.084306) utilized this principle and proposed a geometric state function based on the intrinsic volumes. In a similar approach, we find a geometrical description for free energy of a porous system with two fluids. This is also an extension of the work by Mecke (2000, https://doi.org/10.1007/3-540-45043-2_6) for energy of a single fluid. Several geometrical sets of spatial objects were defined, including bulk of the two fluids, interfaces, and three‐phase contact lines. We have simplified the description of free energy by showing how the intrinsic volumes of these sets are geometrically related. We obtain a description for energy as a function of seven microscopic geometrically independent variables. In addition, using a thermodynamic approach, we find an approximation for the free energy as a function of macroscopic parameters of saturation and pressure under quasi‐static conditions. The combination of the two energy descriptions, by integral geometry and thermodynamics, completes the relation between the associated variables and enables us to find the unknown coefficients of the intrinsic volumes and to calculate the amount of dissipated energy in drainage and imbibition processes. We show that the theory is consistent with a set of experiments performed by Schlüter et al. (2016a, https://doi.org/10.1002/2015WR018254, 2017a, https://doi.org/10.1002/2016WR019815). However, in order to be more conclusive, it needs to be tested with larger data sets.

Low salinity water (LSW) and low salinity surfactant (LSS) core flooding experiments were performed to study the impact of ionic composition on oil recovery from aged Berea sandstone cores. Surfactant adsorption in packed beds, contact angles, interfacial tension (IFT), critical micellar concentration (CMC), and end-point relative permeabilities were used to better understand wettability alteration. In the samples aged with the same in situ brine with (Ca2+ + Mg2+)/Na+ = 0.033, both end-point relative permeabilities of LSW flooding and contact angles showed LSW with only sodium chloride made the samples more water-wet than LSW with divalent-contained brines. Oil recovery was also highest in LSW injection with only sodium chloride. In tertiary LSS of the same core samples, according to both flooding and contact angles, LSS with only sodium chloride showed more water wetness. Characterization measurements showed that, at higher Ca2+/Na+ ratio, CMC and IFT were lower whereas surfactant adsorption was higher. Further, at similar conditions, LSW and LSS made the core sample more water-wet than high salinity water (HSW) and high salinity surfactant (HSS). At low surfactant concentration, LSS recovered as much oil as HSS did.

Permeability and formation factor are important properties of a porous medium that only depend on pore space geometry, and it has been proposed that these transport properties may be predicted in terms of a set of geometric measures known as Minkowski functionals. The well-known Kozeny-Carman and Archie equations depend on porosity and surface area, which are closely related to two of these measures. The possibility of generalizations including the remaining Minkowski functionals is investigated in this paper. To this end, twodimensional computer-generated pore spaces covering a wide range of Minkowski functional value combinations are generated. In general, due to Hadwiger's theorem, any correlation based on any additive measurements cannot be expected to have more predictive power than those based on the Minkowski functionals. We conclude that the permeability and formation factor are not uniquely determined by the Minkowski functionals. Good correlations in terms of appropriately evaluated Minkowski functionals, where microporosity and surface roughness are ignored, can, however, be found. For a large class of random systems, these correlations predict permeability and formation factor with an accuracy of 40% and 20%, respectively.