Published: 08/29/2019
Published: 08/29/2019
Even in clean, well-sorted sandstone reservoirs, traditional fluid saturation evaluation using resistivity-based methods can have a high degree of uncertainty because of potential unknowns, such as formation water salinity. The same evaluation in unconventional reservoirs is further complicated by the presence of kerogen, high-viscosity hydrocarbons, and solid hydrocarbons, affecting the quantification of porosity and producibility.
An operator in the Eagle Ford wanted a more reliable approach to identifying moveable hydrocarbon and other reservoir fluids and mapping their distribution for defining the best landing point for horizontal wells.
Schlumberger recommended CMR-MagniPHI high-definition NMR service as uniquely suited for the evaluation of unconventional reservoirs. With the industry’s shortest echo spacing at 200 us, the service measures T1 and T2 simultaneously and continuously. This capability provides a high sensitivity to fluid contrasts, even in micropores, and is tolerant of the typical low porosity and high formation water salinity of shale reservoirs. The continuous acquisition of T1 and T2 data by CMR-MagniPHI service enables an independent assessment of the fluid volumes and distributions, highlights wettability contrasts, and quantifies bitumen content as an alternative to resistivity-based calculations that conventionally inform the petrophysical model.
Integrating data from CMR-MagniPHI service and Litho Scanner high-definition spectroscopy service accurately defines the kerogen fraction and reservoir producibility index. The NMR measurement responds to the fluids in the pores and is not influenced by the kerogen content. To differentiate the kerogen portion of the total organic carbon (TOC), the porosity determined with CMR-MagniPHI service is compared with the total density porosity corrected for the matrix density obtained from Litho Scanner service. This approach benefits from the accurate matrix density output from Litho Scanner service. The difference between the two porosity curves identifies the amount of kerogen in the TOC determination, and hence the remainder is the volume of producible liquid hydrocarbon.
The saturation interpretation from the T1T2 maps agreed well with core analysis. The petrophysical model was then revised with the saturation data to recalculate the reservoir volumes. Bitumen, which is not readily quantified in conventional approaches, was quantified using the maps, and those values agreed well with retort analysis of the core to further refine the volumetric analysis.
Having established a more accurate, insightful understanding of the Eagle Ford, the operator was able to identify targets for lateral landing points in the zones with the highest producibility.
Challenge: Separate potentially moveable from nonmoveable fluids to guide the selection of the horizontal well landing point.
Solution: Acquire continuous T1 and T2 measurements with CMR-MagniPHI high-definition NMR service for quantifying porosity and fluid distributions in combination with other formation evaluation methods.
Results: Accurately mapped fluid distributions, as verified by core analysis, to revise reservoir volumes and identify zones with the highest producibility as lateral landing targets.
