Mineralogy, Porosity, Fluid Property, and Hydrocarbon Determination of Oil Reservoirs of the Green River Formation in the Uinta Basin

The geologic complexity of Rocky Mountain reservoirs requires innovative techniques in the acquisition and interpretation of log and core data. Similarly, petrophysical models used to determine hydrocarbons inplace and reservoir flow characteristics require innovative solutions. Fortunately, recent advances in core and log technology have enabled better formation evaluation. This paper examines log and core data used to evaluate reservoirs in the Uinta basin, which include intervals that contain hydrocarbons in the solid, liquid, and gas phases. The paraffinic Green River Formation oil has a viscosity that is highly temperature dependent and that affects both log and core measurements. Formation mineralogy includes lacustrine dolomites and various percentages of elastic and carbonate components, as well as numerous clay types and volumes. The evaluation of the hydrocarbon volume is complicated by wettability variations from water-wet to oil-wet in the Green River Formation. Resistivity-based saturation models rely on the knowledge of Archie m and n exponents, which are highly variable and difficult to obtain from core. Many of the intervals appear to be selfsourcing, which may contribute to the varying temperature and pressure gradients. Finally, permeability is often fracture dominated and depends on the fracture orientation and distribution in this tectonically active region. It is apparent that a simple triple-combo log is not sufficient to fully understand the complexities of the Green River Formation, its hydrocarbon volume, or its productivity. Advanced logging technologies, such as nuclear magnetic resonance (NMR) and dielectric, together with core acquisition and their analyses will be discussed as they pertain to the understanding of some of the unique formation characteristics previously identified. In this paper, we also describe the laboratory NMR measurements of preserved core samples performed in "fresh state" and at varying temperatures to study the effects of the paraffinic oil. Laboratory NMR data were used to calibrate the NMR log data, and 2D NMR models were used to identify and quantify the different fluid volumes. A petrophysical model appropriate for these reservoirs was developed and is discussed in the paper. The inversion of both NMR and dielectric data each provide estimates of bulk-volume-water that are fairly water-salinity independent. The combination of these results with laterolog resistivity data provides in-situ determinations of Archie in and n values. NMR, dielectric and triple-combo data are alsocombined in a petrophysical model to determine volumes of solid (kerogen) and liquid hydrocarbons (oil and bitumen). In this paper, the petrophysical model is compared with standard geochemical core analysis. These petrophysical analyses have helped to better understand the characteristics of this reservoir and have been instrumental in-revising estimates of hydrocarbons in-place. This analysis led to changes in completion strategies that have resulted in significant cost reductions.