The evolution of the residual oil saturation as a function of the trapping number N t (capillary number plus Bond number), is generally known as the capillary desaturation curve (CDC) and constitutes an important input parameter in chemical enhanced oil recovery flooding. However, less importance has been paid to the investigation of the influence of oil ganglia evacuation on relative permeabilities. We report on an experimental investigation dealing with the effect of flooding parameters, fluid interfacial properties and rock structure on the CDC and on the water relative permeability. Experiments were performed on a set of water-wet sandstone plugs with different petrophysical properties, and X-ray computed tomography (CT-scan) imaging was used to accurately measure the local oil saturation. Oil ganglia size distribution as well as pore scale geometrical properties was also quantified at the scale of the micrometer using high-resolution micro-computed tomography (MCT). Results showed that the CDC depends on the pore structure and specifically on the average throat radius and the inverse of the relative permeability. Oil ganglia size distribution obtained by MCT follows a typical power law as suggested by percolation theory. We also showed that CDC obtained from macroscopic measurements can be predicted from the measured oil ganglia size distribution and rock structure geometrical parameters. In parallel, we observed that for low trapping numbers, water relative permeability is independent of the trapping number. However, for intermediate trapping numbers, a strong dependence of the water relative permeability on the latter can be noticed. In this range, we showed that water relative permeability has a specific scaling with the trapping number.

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Formation damage is still a controversial subject within the industry especially when it takes place during Produced Water Re-Injection (PWRI). However, there is a consensus that formation damage results from a complex interaction between water quality, petro-physical and rock mechanical properties of the reservoir as well as the well architecture and completion. A lot of experimental work has been made in these last decades to understand and quantify the main mechanisms, parameters governing formation damage due to PWRI and the literature in this domain is plentiful. Nevertheless, a lot of questions are left unanswered particularly when it is a question of unconsolidated sands. This paper describes a core-flooding program performed with sand packs at different permeabilities, variable water qualities and injection conditions. Experiments were performed by injecting well-characterized system that contains either solid particles, mono-sized oil droplets or both of them at various sizes and proportions. It was shown that for mixture of solid and oil particles, the damage approach based on flow of solid suspensions alone doesn't apply and solid particles-oil droplets interaction is to be considered. This paper also details the role of each of the produced water components, their interaction and deposition within the core as well as the subsequent damage they induce. More generally, answer to some practical questions would be provided like: Do solid particles act by their size or concentration? Is oil in water content a key factor? How and where solids and oil deposit? Is there a critical concentration of solid particles and/or oil allowing injecting always in matrix regime and avoid fracturing unconsolidated reservoirs which often lie at shallow depths and in which fracturing can induce cap rock integrity and injection confinement issues? Would it be possible to control formation damage by controlling the injection conditions (flow rate, water salinity, etc…)? The answers provided here would give practical rules to help in adequately designing and optimizing PWRI projects.