An accurate evaluation of water and oil saturations has appeared more challenging in tight organic shales than in conventional reservoirs. In this paper, we describe a nondestructive method allowing the measurement of hydrocarbon saturation based on 2D T1-T2 NMR.
First, we give experimental evidence of an NMR contrast between oil and water in organic shales. Contrary to the condition in conventional reservoirs, the contrast between oil and water in shales is not based on diffusion, but on the T1/T2 ratio. Various imbibition tests with water/ light oil/D2O were performed. These tests prove that the oil and water NMR signals can be assigned unambiguously in 2D T1-T2 NMR maps. They also prove that the high T1/T2 in organic pores is not due to bitumen (high viscosity), and that it can be achieved by light oil (isopar L). The high T1/T2 observed is only due to confinement in the organic pores.
Secondly, multifrequency NMR dispersion (NMRD) experiments were used to understand how confinement only can lead to such a high T1/T2. These experiments allow us to propose an interpretation that explains the unexpected dynamical behavior of the light oil in organic pore leading to high T1/T2.
Finally, water and oil volumes measured by 2D T1-T2 NMR were validated by thermogravimetric analysis (TGA).
Petrophysical properties including porosity, permeability, fracability and hydrocarbon saturation are crucial for hydrocarbon producibility and economic assessment in tight organic shales. Techniques to evaluate these petrophysical properties in tight organic shales have become more challenging. It has been demonstrated extensively that porosity measurement could have significant bias in these rocks (Sondergeld et al., 2010; Le Bihan et al., 2014). Therefore, a proper experimental protocol is required to obtain usable data.