The evolution of pores and fluids due to thermal effects is a key factor for predicting shale gas production. However, different fluid types and a wide range of pore sizes pose difficulties for characterization. We experimentally changed the fluid distribution and maturity of shales by pyrolysis on an Eagle Ford sample and a northern Rocky Mountains sample. Initial fluid conditions of shale samples were determined by NMR T1-T2 measurement. The samples were heated at 110°C, 250°C, 450°C, and 650°C, and T1-T2 measurements were performed after each level. The obtained T1 and T2 distributions were mapped to T1/T2 ratio (R) and secular relaxation time (Ts) for better characterization of different fluid distributions. Further, a difference index was used to quantify the overall distribution difference in R-Ts space.
According to the results, the Eagle Ford sample is dominated by an oil signal, whereas the northern Rocky Mountains sample has a mixture of oil, water and organic matter signal. Fluid volume decreases with increasing temperature. Heating at 110°C or 250°C reduces the fluid volume through the course of evaporation of water and hydrocarbon. The signal of OM is also revealed due to the fluid evaporation. Heating at 450°C and 650°C will alter the maturity of OM, resulting the change of distribution shape of T1-T2 due to change of pore structure. The thermal effects lead two samples to have a similar evolution pattern during thermal maturation.