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Unconventional and conventional reservoirs do not have much in common. They exhibit different reservoir characteristics; therefore, using conventional reservoir interpretation techniques and workflows in unconventional reservoirs could lead to incorrect conclusions. In addition to fundamental challenges in evaluating reservoir properties, such as porosity and permeability, it is extremely important to understand reservoir fluid distribution. Downhole fluid typing and calculated volumes, together with porosity and permeability, provide more insight into reservoir potential and sweet spot zones. Nuclear magnetic resonance (NMR) technology can be used to provide answers to some of the unknowns mentioned previously. Standard NMR measurements provide the lithology-independent porosity and permeability, and then further processing provides more details about partial porosities, volumes, and fluid types occupying the pores. Using two-dimensional maps (2D NMR) helps differentiate the reservoir fluids, especially when distinguishing hydrocarbons (HC) from water. In conventional reservoirs, it is expected to observe faster relaxation for fluid trapped in the smaller pores and longer relaxation for free fluids in the bigger pores. Industry-accepted cutoffs for T1 and T2 measurements help estimate micro, meso, and macro pores. However, for unconventional reservoirs, fluid identification using 2D maps would be different. Fluids in the small pores, such as bitumen, heavy oils, or HCs in source rock reservoir, would have a similar signature on 2D maps. This paper presents two case studies showing how 2D NMR application was used in an unconventional reservoir for fluid typing processes and HC volumes calculation. It also shows the importance of using this method for more precise planning of further downhole activities. Core data analysis and downhole collected fluid laboratory analysis confirmed the high confidence in NMR fluid typing applications for unconventional reservoirs. |
