In the hydrocarbon exploration process, after a prospect has been identified and an exploration well has been drilled, a critical piece of information is the oil type. Earlier wireline or while-drilling well-logging technologies provided rock properties and saturation information, but relied on expensive sampling and testing to determine oil properties.
This weakness was overcome through the introduction of nuclear magnetic resonance (NMR) logs that can provide formation properties—lithology-independent porosity, porosity distribution, permeability, etcetera—and information about the reservoir fluid viscosity.
NMR data were recently acquired in complex, high-clay content, low-salinity oil reservoirs. Traditional petrophysical interpretations throughout these reservoirs were confronted with a complex lithology—comprising feldspathic litharenites and volcanic lithic components—high clay content and low formation water salinity, of 3-4 Kppm NaCl eq.
This extended abstract shows how acquisition and interpretation of NMR data not only provided porosity and porosity distribution, but also identified oil viscosity across the logged intervals. Advanced NMR log interpretation techniques (2D-NMR maps of diffusion (D) versus T2, int) were used to identify oil NMR signal.
This technique produced a continuous profile of diffusion and intrinsic T2 distribution maps. Once the oil NMR signal was identified, an estimation of the oil viscosity was also possible because D and T2, int are related with viscosity. Several available correlations have been used and results were comparable with production data.
Tight Reservoir Properties Derived by Nuclear Magnetic Resonance, Mercury Porosimetry and Computed Microtomography Laboratory Techniques. Case Study of Palaeozoic Clastic Rocks