Many techniques are used in industry to determine reservoir hydraulic connectivity from static data. These can be rock-based techniques such as seismic mapping, well to well correlations and geological modeling. Or they can be fluid based techniques such as pressure and fluid gradients. Fluid pressure gradients acquired with formation testers have long been popular but they are understood to be able to identify a lack of connectivity and cannot necessarily prove the presence of connectivity. Recent work has shown that mapping fluid gradients can be much more definitive. For light fluids this mapping is based on the gas-oil ratio (GOR). For heavier fluids, with little GOR variation, this technique requires mapping a different parameter. It has been suspected that asphaltene content was the parameter to map, but until recently the science of asphaltene prediction was unclear. Recent advances in asphaltene science have now clarified the mechanism for asphaltene distribution in the reservoir and gradient prediction is now possible. And most fortunately it turns out that the asphaltene gradient is relatively easy to measure in-situ. In this paper we present the science behind asphaltene gradient prediction and show how fluid gradients are a superior way to infer reservoir connectivity. We then present data from an Eastern Siberia oilfield where asphaltene gradients are determined in-situ with a wireline formation tester. These gradients are verified by later comparison to laboratory measurements. Finally and most importantly, we show also how the asphaltene content is used to predict reservoir connectivity both vertically and laterally.
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