Reservoir and Containment Risk Assessment for Potential CCS Sites: Case Study from Deepwater Field, Campos Basin, Offshore Brazil
Authors: Mohsin N. , Affandi R. Ahmad , Zainudin W. N. S. W Mohd , Widyanita A. , Sahad S. Mad , Piah M. F. Mat , Musa I. H. , Enggsa Hashim H. Mohd , Kasim F. H. , Chidambaram P. , Amin S. M 
Published: November 2024

Abstract
Deepwater fields in the Offshore Brazil Campos Basin are located approximately 260 km from shore. Gas fields in this ultra-deep-water region are associated with high CO2 content, with deeper reservoirs at a depth of 6000 meters. Therefore, screening for Carbon Capture and Storage (CCS) is crucial to identify suitable nearby storage sites in Campos Basin, thereby mitigating CO2 emissions during the production phases of these high CO2 fields. These deepwater hydrocarbon fields are characterized by their CO2 content, ranging from 15 to 30%, which corresponds to approximately 0.6 to 3.8 Tcf of storage capacity. Various geological settings, such as coalbeds, saline aquifers, or depleted hydrocarbon reservoirs, can be targeted for CO2 storage.
The study emphasized reservoir characterization evaluation, containment risk assessment, and storage capacity at selected nearby saline aquifers and current producing fields within relevant reservoir depths and volumes for storage. This included additional data from other studies, such as geomechanical and geochemical analyses, and injectivity assessments. The high-level CCS screening was conducted using acceptable assumptions and relevant data inputs to conclude a standard screening assessment, ultimately justifying the CO2 management strategy to be integrated into the field development plan. Additional high-level analysis was conducted on geomechanical, geochemical, and well-scale injectivity assessments to partially meet the standard screening requirements and to mitigate the CO2 injectivity uncertainty into the targeted reservoir.
Containment targets were delineated from pre-salt Aptian Macabu Carbonate and post-salt Albian Quissama Carbonate, as well as post- salt clastic formations spanning from the Cretaceous to the Miocene age. Miocene sands have a higher risk due to the absence of seal rock. The post-salt Carapebus turbidite sandstone succession, which includes Namorado sand, Santonian/Turonian sand, and Eocene sand units, is the major prolific reservoir in the nearshore oil field, with ~27% porosity. The pre-salt carbonate is the major oil province in the deepwater region, with ~15% porosity. In the nearshore region, the Quissama Carbonate serves as an oil reservoir with ~20% porosity, but in deeper saline aquifers, it is often characterized by tight carbonate due to overburden and low permeability. Both carbonate formations developed as isolated platforms at the top of basement highs (pre-salt), positioned up-dip of salt bodies (post-salt), rendering them well-preserved within suitable stratigraphic and structural traps with turbidite shale and salt as effective seal rocks, resulting in their classification as low-risk containment targets. Although thick salt bodies provide effective sealing for pre-salt reservoirs, their classification as medium to high-risk containment targets is based on their generally low to medium porosity range.
The study identified the most promising storage sites: one nearby saline aquifer field with a total capacity of 0.8 Tcf and one nearshore hydrocarbon field with a total capacity of 1.4 Tcf (Trillion cubic feet). However, a more detailed examination of these fields is necessary. Additionally, conducting another screening for in-situ storage potential would help in developing a more cost-effective storage plan.