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Enhanced oil recovery (EOR) processes may often involve simultaneous flow of two or three immiscible fluids inside the reservoir. A precise evaluation of relative permeabilities is critical to quantify multi-phase flow dynamics, assisting improved management and development of oil- and gas- bearing formations. This study illustrates the results of laboratory-scale investigations of multiphase flow on a sandstone reservoir core sample to evaluate relative permeabilities under two- and three-phase (i.e., water, oil, and gas) conditions. We use the ensuing information to simulate WAG injection at reservoir scale. The experiments are conducted at high temperature, consistent with reservoir conditions, to obtain two- (oil/water and oil/gas) and three-phase (oil/water/gas) relative permeabilities through Steady-State (SS) technique. Our laboratory workflow allows for an improved investigation by combining coreflooding experiments with in-situ X-Ray evaluation of local saturation distribution. The latter technique permits to asses slice-averaged phase saturation along the rock core, enabling to compute saturation profiles and average saturations while flooding, thus yielding significant advantages over traditional methodologies based on mass balance. Three-phase steady state (SS) experiments are performed by following diverse saturation paths, and the complete experimental dataset is provided to (a) assess the occurrence of local three-phase saturation conditions and (b) possibly investigate hysteretic effects of relative permeabilities. We evaluate three-phase relative permeabilities across the entire three-phase saturation region by leveraging a Sigmoid-based model (Ranaee et al., 2015). The resulting set of experimental two- and three-phase coreflooding results constitute a unique dataset which is then employed for reservoir simulation studies mimicking WAG injection and results are discussed in comparison with reservoir production under a waterflooding scenario.

This paper describes the results of an integrated reservoir study aimed at producing hydrocarbons through a sustainable development from a green High Temperature (HT) giant CO2-rich gas field in the Australian offshore. The development concept addressed the complex challenge of exploiting resources while minimizing the carbon impact. In order to characterize the reservoir in the most detailed way and to describe the fluids behaviour, a 1.8 million active cells compositional model has been built. An analytical aquifer has been coupled in order to represent the boundary conditions of the area. The faults system, interpreted on seismic data by geophysicists, has been included in the simulation model. The selected development plan includes the re-injection of the produced CO2 into the aquifer of the reservoir itself. The supercritical CO2-brine relative permeability curves at reservoir conditions have been provided by Eni laboratories, where the experiments were performed. Therefore, a detailed model has been built with the purpose of: –Defining producing well and CO2 injector well locations, numbers and phasing to evaluate expected CO2 injectivity and CO2 breakthrough issues;–Optimizing the development concept through a risk analysis approach;–Estimating the CO2-rich gas injectivity and storage capacity in the saline aquifer of the reservoir;–Predicting the behavior of the CO2-rich gas after re-injection (breakthrough timing and plume migration);–Maximizing the CO2 sequestration in the reservoir.

We present experimental investigations of two-phase (oil and water) relative permeability of laboratory scale rock cores through a joint use of direct X-ray measurement and flow-through investigations. The study is motivated by the observation that appropriate modeling of oil and water displacement in porous media or fractured rocks requires to be firmly grounded on accurate and representative core flood experiments and their appropriate interpretation. Experimental data embed key information relating relative permeability to observables. In this context, direct measurement of in-situ fluid saturation through X-Ray techniques has the unprecedented ability to characterize key processes occurring during the displacement of immiscible fluids through natural permeable materials. Water saturation profiles determined by X-ray scanner can then be linked to relative permeability curves stemming from two-phase flow experiments. We illustrate the benefit of employing direct X-Ray measurements of fluid saturation through a set of laboratory experiments targeted to the estimate of two-phase relative permeabilities of homogeneous samples (sand pack and Berea sandston core). Data are obtained for a range of diverse fractional flow rates and provide information at saturations ranging from irreducible water content to residual oil saturation. Our X-Ray saturation data are consistent with an interpretation of measured relative permeabilities as associated with water-wet rock conditions. The comparison of different preamble samples result high displacement efficiency and recovery factor corresponds to the high permeable and well-connected pores