Using Field Data to Demonstrate the Importance and Pitfalls of Flow-Unit Interpretation for Reservoir Description and Modeling

Anne-Kristine Stolz¹ and Ramona M. Graves^2
1 SINTEF Petroleum Research, Trondheim, Norway
² Colorado School of Mines, Golden, CO

The concept of flow units, a group of reservoir rocks with similar properties that affect fluid flow, has been developed by the petroleum industry to integrate geological data and interpretation with petroleum engineering simulation applications. This paper demonstrates that the method and data used to define flow units and their corresponding petrophysical properties, do not give a unique solution to reservoir performance prediction.

This study compared seven methods for flow unit definition to a known answer using a simple simulation model in ECLIPSE 100. The data corresponds to the research well CSM Strat Test #61, which belongs to the Lewis Shale. It includes conventional and specialized well log information, and petrophysical core measurements. Flow units were determined based on core analysis, log analysis, neural networks, capillary pressure data, and stratigraphic interpretation. Simulation confirmed that many flow models used lead to inaccurate description of the reservoir. Production rate and volume, as well as reservoir pressure performance, were not correctly predicted by most of the methods. For example, empirical equations for pore throat radius, such as Winland's r35, which is based on mercury injection capillary pressure measurements, cannot be universally applied.

This paper gives concrete results which demonstrate the economic importance of integrating the work of geologists and petroleum engineers in reservoir characterization and flow performance projects. Geologists need to account for flow behavior in the description of a reservoir, while petroleum engineers need to match geological characterization for simulating flow performance.

AAPG Search and Discovery Article #90039©2005 AAPG Calgary, Alberta, June 16-19, 2005