Varieties of enhanced oil recovery (EOR) processes involve simultaneous flow of two or three immiscible fluids (i.e., water, oil, and gas) in reservoirs. Proper quantification of multi-phase flow processes has considerable economic and scientific importance in management and development of oil- and gas-bearing geologic formations. Relative permeabilities are key rock-fluid properties required for continuous-scale modeling of multiphase flow dynamics in porous and fractured media. A reliable characterization of these quantities, including uncertainty quantification, enables reservoir engineers to assess reservoir performance, forecast ultimate oil recovery, and investigate the efficiency of enhanced oil recovery techniques.

In this work, we report the results of a suite of laboratory-scale experimental investigations of multi-phase (water/oil/gas) relative permeabilities on reservoir core sample. Two (water/oil) - and three-phase (water/oil/gas) relative permeability data are obtained at high temperature of the reservoir by way of a Steady-State (SS) technique. Our laboratory methodology allows improved relative permeability acquisition through a joint use of traditional flow-through investigations and direct X-Ray measurement of the core local saturation distribution. The latter renders detailed distributions of (section-averaged) fluid phases along the core, which can then be employed for the characterization of relative permeabilities. The three-phase Steady-State relative permeability experiments have been conducted by resorting to a dual energy X-Ray methodology. The experimental setup also includes a closed loop system to validate and support saturation measurements/estimates. The SS three-phase experiments are performed by following diverse saturation paths including CDI, DDI, IID and some cycle injection of WAG, where, C, D and I denote as Constant, Increasing and Decreasing (i.e., CDI means Constant water, Decreasing oil and Increasing Gas). Several different flow rate ratios have been selected to cover the saturation ternary diagram extension as completely as possible.

The use of in-situ X-Ray scanning technology enables us to accurately measure depth-averaged fluid displacement during the core-flooding test. We observe in most of the tests, three-phase water relative permeabilities display an approximately linear dependence on its saturation when the latter is subject to a logarithmic transformation. The three-phase oil and gas relative permeabilities, when plotted versus their saturations are scattered by apparently quasi-linear trends, compared to the behavior of water relative permeabilities.

We provide the experimental data set to demonstrate the possible three-phase region and eventually investigate the hysteretic effects on three-phase relative permeabilities. As only a limited quantity of three-phase data are available, this study stands as a reliable reference for further model development and testing.


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