GEOLOGICAL MODELLING AND RESERVOIR CHARACTERIZATION OF CARBONATE PRE-SALT DEPOSITS

• Grant number: 25/08237-7
• Support Opportunities: Scholarships in Brazil - Doctorate
• Start date: September 01, 2025
• End date: February 28, 2029
• Field of knowledge: Physical Sciences and Mathematics - Geosciences - Geology
• Principal Investigator: Alexandre Campane Vidal
• Grantee: Vittor Cambria
• Host Institution: Centro de Estudos de Energia e Petróleo (CEPETRO). Universidade Estadual de Campinas (UNICAMP). Campinas , SP, Brazil
• Company: Universidade Estadual de Campinas (UNICAMP). Faculdade de Engenharia Mecânica (FEM)
• Associated research grant: 17/15736-3 - Engineering Research Centre in Reservoir and Production Management, AP.PCPE

Abstract

The geological model needs to include the main geological features and heterogeneities for the reservoir simulation team to be able to properly predict field production over time (LUCIA, 1999; AHR, 2008; SKALINSKI and KENTER, 2015). A good model needs to represent the main faults and fractures, the facies distribution and petrophysical properties such as porosity, permeability as also as the possible barriers that inhibit the oil migration among other features. It is important to capture all the pre-salt carbonate heterogeneities and its uncertainties associated. The Brazilian pre-salt carbonates exhibit a lot of challenges in this respect for example: the low seismic resolution and the occurrence of sub-seismic geological features, such as fractures and vuggy pores, that are responsible for creating high permeable zones; the high heterogeneity of carbonate porosity; and the absence of analogous depositional systems (DE JESUS et al., 2016; HERLINGER; ZAMBONATO; DE ROS et al., 2017; GOMES et al., 2020).This work proposes the generation of new workflows for geological modeling taking into account the main heterogeneities of the reservoir integrating multiscale properties from laboratorial analysis (porosity and permeability calibration) with well logs, seismic attributes and seismic geobodies to highlight the main zones of the reservoir. Beyond that, perform the uncertainty analysis integrating the occurrence of fractures and vug pores. The integration of laboratorial analysis with the well logs will aim at the definition of petrophysical rock types (PRT) (SKALINSKI and KENTER, 2015) that will be related with the seismic geobodies extracted from attributes and geological interpretation. The occurrence of faults and fractures will be extracted from borehole image logs (BHI), when these features are in sub-seismic scale, the characterization includes fracture spacing and permeability, fracture aperture, and fracture porosity. Furthermore, the occurrence of vuggy rich zones is also possible by integrating the CT results from cores with BHI (DE JESUS et al., 2016). The reservoir simulation will be the last step, where it will be possible to correlate the fluid flow pattern of the reservoir with different geological features. To validate these results, production data will be incorporated into the workflow. (AU)