The Limits Of Fluid Property Correlations Used In Nmr Well Logging An Experimental Study Of Reservior Fluids At Reservoir Conditions

Nuclear magnetic resonance (NMR) well logging has matured over the last decade into a powerful evaluation tool delivering formation properties such as total porosity, fluid typing, producible fluid fractions and permeability indicators. Recent advances in NMR research and tool development have expanded these capabilities to include new products designed to deliver physical properties of reservoir fluids directly from downhole NMR measurements (Prammer, 2001, Freedman, 2000). Careful selection of appropriate logging parameters typically enables the determination of representative NMR characteristics of formation fluids, such as distributions of relaxation times and diffusivity. However, accurate interpretation of NMR logs and subsequent prediction of fluid properties, depend on the model that relates the measured NMR response to in-situ physical properties. For several years, fluid properties have been derived from NMR measurements by correlating relaxation time characteristics to hydrocarbon viscosity. Due to experimental limitations, these relations have mostly been developed at ambient pressure by either measuring a range of crude oils, or by changing fluid temperature (Vinegar, 1995). This paper summarizes some results of our research aimed at expanding current understanding of the NMR response of reservoir fluids. Our experiments involved laboratory measurements on a variety of fluids ranging from common base drilling fluids to oils containing a significant amount of solution gas. We found that standard models currently used in the industry do not adequately predict pressure-induced changes of NMR relaxation and result in poor correlations between viscosity and relaxation time. Our measurements show that for typical formation pressures, standard correlations may lead to an underestimation of viscosity by a factor of three. We explain how the observed effect of pressure on relaxation relates to both inter-and intramolecular interactions. For reservoir fluids containing a significant amount of solution gas, the transverse (T2) and longitudinal (T1) NMR relaxation times can be additionally reduced by spin-rotation of methane molecules. In recent years published attempts have been made to quantify this reduction, and furthermore, to use this effect to predict the solution gas-oil ratio (GOR) (Lo, 2000). We have found that the complex interplay of intramolecular relaxation, pressure-induced changes, and spin-rotation causes such a prediction to be unreliable and we observe an overestimation of GOR in some cases by a factor of ten. Nuclear magnetic resonance (NMR) well logging has matured over the last decade into a powerful evaluation tool delivering formation properties such as total porosity, fluid typing, producible fluid fractions and permeability indicators. Recent advances in NMR research and tool development have expanded these capabilities to include new products designed to deliver physical properties of reservoir fluids directly from downhole NMR measurements (Prammer, 2001, Freedman, 2000). Careful selection of appropriate logging parameters typically enables the determination of representative NMR characteristics of formation fluids, such as distributions of relaxation times and diffusivity. However, accurate interpretation of NMR logs and subsequent prediction of fluid properties, depend on the model that relates the measured NMR response to in-situ physical properties. For several years, fluid properties have been derived from NMR measurements by correlating relaxation time characteristics to hydrocarbon viscosity. Due to experimental limitations, these relations have mostly been developed at ambient pressure by either measuring a range of crude oils, or by changing fluid temperature (Vinegar, 1995). This paper summarizes some results of our research aimed at expanding current understanding of the NMR response of reservoir fluids. Our experimen