Porosity characterization of complex silicified carbonates reservoirs of BM-C-33
P.H. Vieira de Luca, A. Waldum, A.S. Chandler, D. Hunt, O.P. Wennberg, G. McQuenn, D. Hulme, E. Castro, L. Loures, J.L.D.L. Matias, I. Søreide and A.M.D.C. Filgueiras
Event name: First EAGE Workshop on Pre-Salt Reservoir: from Exploration to Production
Session: Session IVA
Publication date: 06 December 2019
Info: Extended abstract, PDF ( 547.84Kb )
Price: € 20
Block BM-C-33 sits in the SW quadrant of the Campos Basin, approximately 200km off the coast of Rio de Janeiro, Brazil. Three discoveries (Seat, Gávea and Pão de Açúcar) were made between 2009 and 2012. Following appraisal, these are now believed to hold reserves of more than one billion barrels of oil equivalent. Reservoirs in Block BM-C-33 were growing in the outer Campos Basin during the Aptian. They sit on top of rotated and eroded fault blocks and paleo volcanic highs. On a regional scale, they can be viewed as a distal continuation of the Coqueiros and Macabú formations. Seismically, the accumulations are characterized by a wedge-shaped and mounded external geometry (Hunt, et al., 2019). The reservoirs of BM-C-33 are unique. The original rock has been subject to a range of diagenetic processes which completely have altered the original mineral assemblage and pore textures. The resulting reservoir rock displays a complex pore network - different from what is observed in other pre-salt reservoirs. Silica is a key component in the reservoirs of BM-C-33. According to recent works (Lapponi et al, 2019, Tritlla et al, 2018; Tritlla, et al, 2019), the origin of the silica is both early, during or shortly after deposition; and late, associated with hydrothermal activity most likely in Mid Albian (Tritlla et al, 2018). Pore types are diverse and pores range in size from micro porosity to meter scale caverns. Measurements of permeability at different scales reflect this diversity. Permeability measurements on SWC’s capture matrix properties and are generally low (a few mD and below). DST’s on the other hand suggest average reservoir scale permeabilities of several hundreds of mD. Frequent and occasionally massive mud losses during drilling of reservoir sections confirm the presence of large-scale pore systems. Reservoir properties in carbonate reservoirs are closely tied to pore types. NMR and BHI (BoreHole Image) logs are keys for typing of matrix and larger scale pores respectively. Lack of whole core and production logs make conceptual models important but alternative scenarios are carried forward to capture the uncertainty span. Characterization of reservoir properties in BM-C-33 depends on multidisciplinary work and integration of data on a wide range of scales. Whilst the matrix holds most of the hydrocarbon in place, excess permeability features as fractures, faults, connected vugs and caverns control flow. This abstract discusses some key features and the work that has been done to characterize them.