Characterizing the quality and quantity of hydrocarbons associated within shales is important for evaluating a formation for future production. Traditional methods utilizing Nuclear Magnetic Resonance (NMR) which rely on the use of T2 relaxation are not sufficient in shales due to the nano-scale nature of the pores. Instead, we propose the use of differential T1 and T2 maps to represent a characteristic change in the sample. We performed thermogravimetric analysis (TGA) along with Pyrolysis Gas Chromatography-Mass Spectrometry (Py-GC-MS) measurements of Bakken, Utica, and Eagle Ford cores at various temperatures and compared them to these T1 and T2 differential maps in order to correlate fluid type. Additionally, at higher temperatures, we believe the maturation of kerogen is evident via a gradual change in peak locations in the T1 and T2 maps, which is difficult to quantify with T2 and diffusion maps due to the low diffusion rates of kerogen.