Asphaltene Gradient in a Deepwater Oil Reservoir as Determined by Downhole Fluid Analysis

Abstract

Abstract The fluids in large reservoirs can be in equilibrium - especially if conditions conducive to convective mixing prevail. A large vertical column of reservoir hydrocarbons offers a unique laboratory to investigate potential gravitational grading. Asphaltenes are known to exist in crude oils as a colloidal suspension, but which had not been well characterized in the laboratory until recently. In this paper, we review a gravitational gradient of asphaltenes in a reservoir and a simple theory is shown to apply. The corresponding downhole and laboratory analyses are consistent; asphaltenes exist in these crude oils in nanoaggregates. The corresponding asphaltene gradients provide a stringent and new method to test reservoir connectivity (as opposed to compartmentalization), which is key to the efficient economic development for many deepwater projects. Introduction In the past, a presumption of fluid homogeneity in the reservoir prevailed. In part, this assumption was made because dynamic calculations performed on reservoir models had difficulty accounting for any but the most basic of fluid compositional gradients. The conclusion followed "if it can't be modeled why do I need to know about it"? It turns out what you do not know can hurt you. There is a growing realization that fluids indeed are often heterogeneous in the reservoir;[1–3] this after all is earth science, where little is homogenous. A variety of factors can lead to hydrocarbon compositional grading including gravity,[4] thermal gradients,[5] biodegradation,[6] active charging, water washing, and leaky seals. Most of these mechanisms cause fluid disequilibrium in the reservoir, and thus become very difficult to model. In addition, reservoir compartmentalization leads to discontinuous compositional contrasts, but in turn identifying these discontinuities may provide a means to identify compartments. Since many of these physics mechanisms that produce compositional variation are time dependent, the existence of fluid distributions can depend on relative rates of fluid movement. Both convection and diffusion generally cause reservoir fluids to move towards equilibrium, but at very different rates. Diffusion can be very slow across a reservoir, (eg. ∼100 MYr) many dynamic processes involving reservoir fluids will be faster.[7] On the other hand, convection is fast (∼1 MYr), thus if convection occurs, oil columns can rapidly move towards equilibrium.[8] In high cost arenas such as areas of deepwater development, one of the biggest impediments to unraveling fluid complexities in the reservoir is to obtain sufficient data. The new technology of Downhole Fluid Analysis (DFA) has proven very useful for the early identification of fluid gradients [9,10] and compartmentalization during the Exploration and Appraisal stage.[2,11] DFA is an objective and a vision ultimately to provide a continuous downhole fluid log; it is performed by specific tools such as the LFA (Live Fluid Analyzer) which performs spectral analysis of crude oils downhole immediately after removing the oil from the formation.