Reservoir Geology Aspects of Lula Supergiant Field, Santos Basin – Brazilian Pre-Salt Province
Discovered in 2006 in the Santos Basin – with reserves estimated between 6.5 to 8.3 Billion boe – Lula field currently has more than 95 drilled wells, holding the largest database in the Brazilian Pre-Salt Province. It is worth to highlight the huge available rock information (more than 4000 sidewall samples and 700m of cores), in addition to 3D seismic, well logs, petrophysical analysis and dynamic data including well tests, pressure and production/injection history.
This vast data collection allows the understanding of the main depositional controls involved in the genesis of the reservoir rocks and the how they are distributed. This ultimately serves as a background to understand the variations of the main petrophysical properties affecting the fluid dynamics in the reservoir, and, consequently, to support a robust strategic development plan for the production.
Deposited in a stressing lacustrine setting in the context of the opening of South Atlantic Ocean, the Barra Velha Formation (Aptian) corresponds to the main reservoir interval of the field. From its genetic and environmental significance, especially the energetic conditions and water depth, the identified sedimentary facies in this interval were grouped into six (6) facies associations: Carbonates with well-developed shrub-like textures (InSitu-shrubs); Carbonates with incipient shrub-like or crust-like textures (InSitu-incip); Reworked Carbonates (RC); Reworked Carbonates with siliciclastic content (RC-si); Low energy (LE) and Lithologies with high content of Clay minerals (Clay).
The analysis of the facies associations stacking patterns along all wells allowed the construction of a high resolution sequential stratigraphic framework, supporting the understanding of the lake environmental conditions evolution - in space and time - and, consequently, of the sedimentary facies distribution in Lula field geological record.
The reservoir vertical and lateral facies distribution have been represented in 3D geocellular models - within a high-resolution stratigraphic framework - by using the conceptual geological model and all the hard data gathered in order to obtain a more reliable distribution of the petrophysical properties. The depositional facies controls a rock-type classification, which is based on porosity, permeability, pore-throat size distribution and relative permeability to support the oil volume estimates, fluid flow modeling and finally the development plan of the field.
AAPG Datapages/Search and Discovery Article #90323 ©2018 AAPG Annual Convention and Exhibition, Salt Lake City, Utah, May 20-23, 2018