The Vankor field development in Russia's Eastern Siberia involves the exploitation of moderately viscous oil from medium to low permeability reservoirs. The field is on production from two different layers, both of which have active aquifers and are supported by water injection. Conventional petrophysics in the field can be difficult and fluid typing is often ambiguous. Downhole fluid analysis with wireline formation testers (WFT) is frequently used to assist in the clarification of petrophysical challenges.However, formation tester operations are not straightforward. Lower permeability and higher oil viscosity means that the WFT probe does not allow sufficient area for fluid to flow. Inflatable dual packer devices are therefore required. The inflatable packer, however, brings its own challenges. With a larger volume of reservoir being investigated longer pump times are required to evacuate invaded filtrate. Additionally, issues associated with the relative permeability of water and heavier oil frequently mean that hundreds of litres of fluid often must be pumped before the fluid typing questions are resolved. In this paper we discuss the implementation of a modified formation tester tool that uses an inflatable packer arrangement configured with dual intake ports. Each of the intake ports is supported by an independent pump and fluid analysis section. Such a configuration offers two benefits. Firstly, the simultaneous operation of two pumps allows the evacuation of larger amounts of fluid in a given time. Secondly, and more importantly, the positioning of the intake ports within the dual packer module allows the tool to take advantage of the density segregation occurring in the packed off interval and to arrive at a clean oil flow much more quickly than a standard configuration. Field examples and lessons learned are provided.

The Verkhnechonskoye oil and gas field in Eastern Siberia produces from a highly complex Precambrian, lower Vendian sandstone. In this reservoir there has been significant post-depositional alteration due to diagenesis, secondary porosity is common and salt, anhydrite and carbonate cementation of the porosity frequently occurs. In short, the reservoir provides substantial petrophysical challenges. In the development of a petrophysical model three specific concerns were noted. Firstly, the effects of the salt-filled pore spaces complicate the determination of porosity and therefore permeability. Secondly, it is difficult to resolve permeability predictions from logs, core and formation testers. Finally, using conventional petrophysics, even with a comprehensive suite of logs and extensive core data, it is difficult to clearly delineate gas-filled porosity from oil-filled porosity and the determination of the gas-oil contact was therefore uncertain. This paper will discuss how petrophysical data from traditional triple-combo measurements was integrated with NMR measurements, core analysis data and formation tester data including permeabilities from pressure transient analysis (PTA) to produce a coherent and robust petrophysical model for permeability prediction.

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The Vankor oilfield in Eastern Siberia is characterized by multiple layers of varying types of hydrocarbons, including oils ranging in viscosity from less than 1 cp to over 20 cp, the Russian regulatory cut-off for heavy oil. It is important for every reservoir penetration to determine the type of oil encountered and also to make any possible inferences about reservoir connectivity. Wireline formation testers equipped with downhole fluid analysis (DFA) sensors acquiring color and gas-oil ratio data (GOR) are used to determine the hydrocarbon type and fluid property gradients. Then, using the emerging technology of asphaltene gradient modeling and prediction for heavier oils, we are able to help support conclusions of reservoir connectivity.In this paper we present datasets from wells where we determine the fluid type from DFA data. Additionally, we incorporate color with pressure gradient data to help build reservoir models that predict reservoir connectivity and compartmentalization.

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.