Combining NMR and Conventional Logs to Determine Fluid Volumes and Oil Viscosity in Heavy-Oil Reservoirs

Abstract The presence of viscous oil in a reservoir greatly complicates the interpretation of NMR log data. Because the NMR signal from an oil with a viscosity greater than 1,000 cp in the sub-surface typically decays with a T2 time-constant that is comparable to that of capillary-bound or clay-bound water, it is impossible to distinguish the signal from the oil phase from that of the bound-water phases. Various petrophysical quantities, such as permeability and fluid volumes, that are normally derived relatively directly from NMR measurements, thus require a significant additional interpretation effort if they are to be determined in reservoirs containing viscous oils. Work published by other authors shows that signal (porosity) loss in viscous oils is a predictable function of the viscosity and the interecho spacing used in the NMR CPMG acquisition sequence. Therefore, a reasonable estimate of viscosity can be obtained by combining the NMR logs with conventional logs to estimate the NMR signal loss at a specific interecho spacing. When this method is combined with NMR diffusion measurements, the volume of movable water can be estimated. Further combinations of conventional and NMR log data provide the quantity of capillary-bound water and a good estimation of permeability. Log examples are available from areas where viscous oils are problematic to users of both conventional and NMR data. These examples are presented to introduce and demonstrate these new methods. Introduction Heavy oil and bitumen account for roughly 6 trillion barrels of the world's known oil reserves, the vast majority of which is found in Venezuela, Canada, and the Former Soviet Union.1 Most of the heavy oil produced in the United States comes from fields in California, Wyoming, Utah, Texas, Kentucky, and Mississippi. The term heavy oil in the context of this paper refers to oils having API gravity lower than 20° and viscosity at formation conditions above 100 cp. These hydrocarbons generally pose challenging production problems and are marketed at a discounted price, however, improved technology and higher oil prices have combined to make exploitation of heavy oil deposits more economically attractive. In addition to the multitude of production and processing problems associated with heavy oils, evaluation of petro-physical properties from NMR logging measurements can be complicated for a number of reasons. Heavy oil NMR responses are similar to signals from capillary-bound water. Furthermore, heavy-oil chemistry may be conducive to a wettability alteration2 that may contribute to a misinterpretation of water content from conventional and NMR logs. These phenomena make it difficult to quantify fluid volumes in heavy-oil reservoirs from NMR measurements alone. Present-day NMR logging instruments do not fully capture heavy-oil signals because they operate at interecho 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 too small, as though the reservoir fluid had a hydrogen index (HI) smaller than one. LaTorraca, et al., have shown how the NMR signal loss in these situations is related to oil viscosity and interecho spacing.3 These factors make it necessary to apply additional interpretation methods to obtain indications of altered wettability and evaluate petrophysical quantities such as fluid volumes, permeability, and apparent in-situ oil viscosity. The methods outlined in this paper rely on combinations of NMR and conventional wireline logs to determine the signal loss and estimate the viscosity of oils whose in-situ viscosity is larger than a few hundred centipoise. Additional combinations with conventional logs can be formed with NMR diffusion measurements to infer movable and capillary-bound water volumes which can be used to refine interpretations of resistivity logs, indicate altered wettability, and provide an improved estimate of permeability in heavy-oil reservoirs.

Fetched live from OpenAlex and de-inverted. Abstracts are not stored in this database: the inverted indexes are 8.6 GB of the frame’s 9.3 GB of text, and the host has 13 GB free.