Understanding Oil Quality Variability In A Carbonate Reservoir Of Oman
Authors: Taylor P. N. , Tegelaar E. , Al Belushi A. S. , Al Fazari B. 
Published: November 2024

Oil columns within carbonate reservoirs may show very large differences in petroleum fluid compositions, which presents a challenge to reservoir characterization, appraisal, development and production. A single carbonate reservoir in Oman contains oil of highly variable quality; with API gravities between 12 and 25 degrees and dead oil viscosities between 32 cP to 2,480 cP at reservoir temperature. Furthermore, oil samples collected at different times from individual wells also showed variability in their physical properties. An improved understanding of the causes of the observed variability was needed to support production operations and to assist well placement and field development strategy & optimization.

Thirteen wellhead oil samples were analysed at different laboratories to determine dead oil viscosity and API gravity, and a sub-set of oils representing the range of observed oil quality was then selected for analysis by multiple methods to characterize the full boiling range of the fluids – from volatile gasoline range hydrocarbons to heavy polar fractions. Relationships between physical properties of oils and their molecular composition were used to determine the causes of the observed variability and construct a conceptual model that can form a basis for fluid quality prediction.

The physical properties of the oils appeared to be directly related to the concentrations of asphaltenes and resins which, in turn, were controlled by differences in thermal maturity. There was no evidence for biodegradation in the oil geochemistry results, despite a present-day reservoir temperature of approximately 70°C.

A model is proposed in which the reservoir was initially charged with heavy asphaltenic oil that was expelled from a nearby Huqf source rock in the earliest part of the oil window. Further burial and maturation of the source rock resulted in progressively lighter and less viscous oils being expelled into the carrier system. Each migrating oil pulse, with lower density and greater buoyancy than the previous one, would migrate to the top of the trap, where it displaced the earlier charge downward. Such a model can explain the range of fluid properties observed, and the general pattern of decreasing oil quality with increasing reservoir depth and is consistent with charge models observed in other carbonate fields worldwide. Lateral variations in the vertical gradients derive from proximity to reservoir charging points, impediments to lateral fluid flow caused by structural compartmentalization or reservoir facies and potentially by localized fracture zones.

The abundant non-hydrocarbon content of the oils, which control physical properties, is also responsible for the tendency of the oils to form extremely stable water-in-oil emulsions due to the presence of heteroatomic functional groups. Such emulsions contributed to significant measurement uncertainty in oil density and viscosity.

A robust proxy for oil density and dead oil viscosity was developed using SARA-type bulk compositional analysis. This may be used to assess fluid property variability from analysis of both oils and reservoir rock samples and has the benefit of being unaffected by the presence of water. The ability to generate data from rock samples makes it possible to create high resolution maps of oil properties via analysis of cuttings samples collected along lateral well bores.