Applying Laboratory Validated EOS-Based Downhole Fluid Characterization to Delump Downhole Fluid Analysis Compositions for Reservoir Continuity Analysis
Authors: Sheng Guo Shu , Jun Cai , Jun Yang Hong , Kin Khong Chee , Zuo Julian , Fujisawa Go , Hausot Andreas , O'Keefe Michael , Mullins Oliver C. 
Published: July 2010

Formation fluid samples can be obtained as surface samples or downhole samples. However, surface sample sampling requires the well to be completed and with production to surface of reservoir fluids from a one or more zone or sometimes multiple zones produced to surface. Downhole sampling can be performed without completing the well by using a formation tester in open hole or performed after completion. In addition, surface samples acquired by flowing the well tend to integrate the fluid over large vertical intervals in the well thereby precluding measurement of fluid gradients. In contrast, wireline sample acquisition and analysis enables vertical and, with multiple wells, lateral gradients to be resolved thereby greatly improving the understanding of the reservoir fluids. Sampled reservoir fluid produced from a zone or multiple zones is not as descriptive compared to point sample using a formation tester. Finally, fluid samples can be sent to the laboratory for analysis but this usually takes a long time; wireline sample acquisition with downhole fluid analysis plays a key role in elucidation of the complexities of reservoir fluids and often time the collected sample is just analyzed using available equipment at the wellsite.

Downhole fluid analysis (DFA) can be performed during sample acquisition with wireline formation testing tools. Sampling operation DFA can identify fluid type, contamination and possible phase changes thereby validating acquisition of a clean, single phase sample of the reservoir fluid if sampling is performed above bubble point pressure. Beyond simply obtaining a valid sample, DFA is used to determine many fluid parameters including compositional measurements such as weight mass fraction of percentages of CO2, C1, C2, C3–C5 or (C2–C5) and C6+ and relative asphaltene content enabling determination of gas oil ratio (GOR) or condensate gas ratio (CGR) derivation. Other currently available DFA measurements are insitu density and viscosity and calibrated fluorescence. Moreover, in special cases, the mass fraction of (diatomic) nitrogen can be determined using the ‘missing mass’ approach.

In this paper, laboratory validated EOS-based downhole fluid characterization that delump C3–C5 (or C2–C5) and C6+ into full-length compositional data was applied to the DFA examples in case studies to maximize the value of DFA data. Particular focus is placed on analysis of CO2 and N2 non-hydrocarbon gases. The gas samples acquired in the examples discussed here were not analyzed at laboratory and only assayed by DFA and by available well site equipment only to C4, giving CO2, N2 and hydrocarbon gas fractions. Reservoir fluid characterization is optimized for this DFA measurement by comparison with an Equation of State (EOS) analysis. Specifically, improved by using an algorithm for delumping, the DFA measurements were validated using laboratory validated Equation of State (EOS)-based analysis downhole fluid characterization algorithm. The delumped DFA measurements were used for flow assurance, hydrocarbon source and compartmentalization analysis. The gas samples' phase envelopes derived from the delumped DFA measurements are used for reservoir characterization, reservoir continuity analysis and management decisions.