In hydrocarbon reservoirs, fluid types can often vary from dry gas to volatile oil in the same column. Because of varying and unknown invasion patterns and inexact clay volume estimations, fluid types differentiation based on conventional logs is not always conclusive. A case study is presented utilizing advanced nuclear magnetic resonance (NMR) techniques in conjunction with the latest downhole fluid analysis (DFA) measurements from wireline formation testers to accurately assess the hydrocarbon type variations.

The saturation profiling data from an NMR diffusion-based tool provides fluid typing information in a continuous depth log. This approach can be limited by invasion. On the other hand, formation testers allow taking in-situ measurements of the virgin fluids beyond the invaded zone, but only at discrete depths. Hence, the two measurements ideally complement each other.

In this case study, NMR saturation profiling was acquired over a series of channelized reservoirs. There is a transition from a water zone into an oil zone, and then into a rich gas reservoir, indicated by both the DFA and the NMR measurements. Above the rich gas is a dry gas interval that is conclusively in a separate compartment. Diffusion-based NMR identifies the fluid type in a series of thin reservoirs above this main section, in which no samples were taken. NMR and DFA both detect compositional gradients, invisible to conventional logs.

The work presented in this paper demonstrates how the integration of measurements from various tools can lead to a better understanding of fluid types and distribution.

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