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Modifying the chemistry of injection water yields improved wettability behavior on carbonate rock surfaces. Previous work has focused on demonstrating the effect of modified brine formulation on particular carbonate samples. Here the results of a more general screening study consisting of Amott spontaneous imbibition experiments on the samples from oil-bearing zones and from outcrops of different carbonate formations are reported. Tertiary incremental oil production due to increased water-wetness was observed upon transition to brine of lower ionic strength. Additional oil recovery from the spontaneous imbibition tests ranged from 4 to 20% of OIIP (Oil Initially In Place), reflecting a large variability in the response and indicating a high complexity of the mechanism(s). Consistent with numerous published reports, Stevns Klint outcrop chalk samples were a clear exception and exhibited increased oil recovery with increasing sulfate ion concentration. These did not respond to lowering the salinity of the imbibing brine. Tertiary oil recovery from samples containing evaporites occurred simultaneously with dissolution of salt minerals, as evident from brine analysis. However, incremental oil recovery in the same range was measured for samples without evaporites but from the same geological formation. Hence, mineral dissolution as a mechanism for enhanced oil recovery could not be confirmed. The results show that injection of low salinity brine into carbonate reservoirs has potential as an EOR technology. However, additional research is needed to improve the understanding of the underlying chemical and physical mechanisms and improve a priori predictability.

Injection of acids and CO2 into geologic formations leads to dissolution of soluble minerals comprising reservoirs rocks. This increases the uncertainty in predicting the security and injectivity of geologic CO2 storage. Here through time‐lapse computed tomography of injection experiments, we present the first dynamic data on wormhole formation and the fluid flow therein. We show that the dissolution during single‐phase flow produces wormholes, as found previously, but that two‐phase flow during CO2‐brine injection leads to compact dissolution. The latter is explained by CO2 preferentially occupying wormhole seeds, which prevents their growth as CO2 is less reactive than acidic brine. On the other hand, the wormhole seeds continue to grow under single‐phase flows with only acidic fluid. The results also suggest that initial Péclet and Damköhler numbers for the single‐phase flow process would fail to describe the dynamic process of whether compact or wormhole dissolution would ensue.

The performance of carbon disulfide (CS2) as a novel agent for enhanced oil recovery has been investigated by conducting a comprehensive series of core flooding experiments where in porous rock, CS2 miscibly displaces “oil” (model fluids such as n-Decane, mineral oils, and crude oils) with a large range of viscosities and field-relevant flow rates. The recovery of oil and the three-dimensional spatial distribution of injected and displaced fluids were obtained from x-ray computed tomography. In all experiments, the displacement was unstable. The dominating displacement patterns were gravity under-run of the more dense CS2, channeling in higher permeable layers and viscous fingering. Since CS2 was fully miscible with all considered fluids, no difference in behavior between model fluids and crude oils was found. The recovery after injection of one pore volume of CS2 was parametrized using the dimensionless scaling groups Péclet number, gravity to viscous forces ratio G, and the logarithmic viscosity ratio R. At small viscosity ratios and large flow velocities (viscous dominated flow, small values of G), recoveries over 90% were observed. Slower flow and more viscous oils reduce the oil recovery.

a b s t r a c tThe displacement of brine by CO 2 is an important process controlling plume migration and initial porespace utilization in geological CO 2 storage. We present CO 2 -brine unsteady-state core flood experiments to characterize CO 2 -brine primary displacement in Estaillades limestone, a model system for dualporosity carbonates. We analyze the experiments by means of numerical simulations assuming 2-D homogeneous rock and parameterized k r (S W ) relationships. Assisted history matching methodologies were used to find the k r (S W ) parameters which minimize a mismatch function, giving the best match to the experimental data. We refer the results to the microscopic rock structure and we discuss the limits of applicability. Larger-scale heterogeneity was considered as intrinsic to arrive at a practical and upscaled description of the displacement process. Heterogeneity is discussed by comparing the results to classical relative permeability measurements on samples with a 24× smaller volume, which are less affected by heterogeneity. We found that larger-scale heterogeneity results in lower fluid-phase mobilities.