As we strive to complete more complex reservoirs, we are challenged to better understand the nature of the fluids contained within. In the North Sea, classical "black oils?? are still encountered; however scenarios where volatile fluids that exhibit a bubble point are found in close proximity to fluids with dew points are not uncommon. In addition, knowing the CO2 content is paramount to completion engineering and facility design with high penalties incurred when CO2 quotas or production limits are exceeded.

Characterizing these fluids is difficult. Typically wireline formation testers with fluid analyzers are used for early fluid characterization and sampling. However, with the increasing fluid complexity subtle differences need to be understood. This requires comprehensive compositional analysis, high resolution answers and quantified accuracy.

This paper describes the technology and answers provided by an accurate in-situ fluid analyzer. Several case studies are discussed. In the first example oil is sampled from two depths, only a few meters apart. The in-situ fluid analysis data from these two depth, including C1, C2, C3-C5, C6+ CO2, GOR and density are compared, indicating excellent tool resolution. In addition these data are compared to laboratory sample analysis result with observed differences falling well within the quoted tool accuracies. A second example involves several closely stacked reservoirs. An in-situ compositional analysis was obtained for each reservoir fluid. By changing the flow rate of the formation tester downhole pump the flowing pressure was manipulated. This allowed to measure different ranges of bubble point pressures for each fluid. Only a few meters below a second fluid exhibiting a dew point was encountered. An indication of the fluid dew point pressure was detected by again manipulating the flowing pressure. Fluid analysis revealed compartmentalization and fluid grading through the different reservoirs in this well.