Heavy oil refers to oils having an API gravity lower than 20° and viscosity at formation conditions above 100 centipoise (cp). These hydrocarbons generally pose challenging production problems and are marketed at a discounted price. However, the combination of improved technology and higher oil prices make the exploitation of heavy-oil deposits more economically feasible. Besides the quantity of production and processing problems associated with heavy oils, evaluating petrophysical properties from nuclear magnetic resonance (NMR) logging measurements can be problematic because of a number of issues, such as heavy oil NMR responses are similar to signals from capillary-bound water.

Additionally, heavy-oil chemistry can be conducive to a wettability alteration that can lead to a misinterpretation of water content from conventional and NMR logs. These phenomena make it difficult to quantify and type fluid volumes in heavy-oil reservoirs from NMR measurements alone.

NMR logging instruments sometimes do not fully capture heavy-oil signals because they operate at inter-echo spacings that make them unable to adequately sample important rapid decay components when viscosity exceeds ~1000 cp. This situation causes the indicated NMR porosity to be somewhat small, as though the reservoir fluid had a hydrogen index (HI) smaller than one, as occurs in gas reservoirs.

These factors make it necessary to apply advanced interpretation methods to find indications of altered wettability and evaluate petrophysical quantities, such as fluid volumes, permeability, and apparent in-situ oil viscosity.

The method consists of combining NMR and conventional wireline logs to measure the signal loss and estimate the oil's viscosity where the in-situ viscosity is larger than a few hundred cp. Additional combinations with conventional logs can be formed with NMR diffusion measurements to infer movable and capillary-bound water volumes. These volumes can then be used to refine interpretations of resistivity logs, indicate altered wettability, and provide an improved estimate of permeability in heavy-oil reservoirs.

This paper shows the validation of this method implemented in over 20 wells in the Suriname-Guyana basin. The average well depth is approximately 1,000 ft, bottomhole temperature (BHT) is ~100°F, and gravity is in the range of 10 to 20 API. The results are validated with production data.

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