TY  - DATA
AU  - Carpinelli,Aldo
AU  - Zurita,Enrique
AU  - Valderrama,José Manuel
AU  - Soto,Luis
AU  - Radic,Juan Pablo
AU  - Agurto,Cristóbal
AU  - Sánchez,Jesús
ED  - Congreso de Exploración y Desarrollo de Hidrocarburos (11er : 2022 nov. 8 - 11 : Mendoza)
TI  - EXPLORACIÓN Y DESARROLLO EN COMPLEJOS TURBIDÍTICOS DEL PALEOCENO TARDÍO - EOCENO MEDIO EN LA CUENCA DE MAGALLANES, CHILE
U1  - 068.82 553.28 C62 15730 
N2  - Cahuil gas field is the first known commercial gas/condensate field of a new exploration play in the Magallanes Basin, associated with Paleocene turbidites from north and east provenance. It was discovered in 2016 north of Magellan Strait and 12 wells have been drilled in it, which has shed interest to expand the exploration on similar leads. Reservoir distribution follows north-east axial direction reaching 20 km in length and 1-3 km in width. The reservoir is composed of quartz-feldspathic lithic sandstones, with shale volumes lower than 25% and mainly constituted by chlorite. Known gross thicknesses are 10-70m, effective porosity is 15-20%. Permeability is 0.02-0.83 mD and average water saturation is 59%. Deposition of the reservoir took place as a superposition of NE oriented channels along a narrow, sandy mudstone submarine ramp. Avulsion and faulting of turbidite channels resulted into internal complexity of the reservoir, which was generically termed "Complejo Arenoso del Grupo Bahía Inútil" (Sandy Complex of Bahía Inútil Group, or CABI). The hydrocarbon trap for this play is mixed structural-stratigraphic, associated to the west-dipping, regional monocline produced by the compressive foreland tectonic phase of the basin, which started in the Late Cretaceous. Local structure of the Cahuil Gas Field is caused by transcurrent tectonics since the Late Oligocene until present day. Hydrocarbon migration and trap charge seem to have been controlled by subvertical fault conduits, connecting Early Cretaceous source rocks to Paleogene and Neogene reservoirs. The Cahuil Gas field is regarded as a tight gas sand reservoir and the original production pressure is 7200 psi. Gas production is improved by hydraulic fracturing which is responsible of initial gas rates (under controlled conditions) of 180-250 Mm3/d, and gas to condensate ratios of 6000-10000 m3/m+. Systematic gas rate and pressure measurements allowed to perform rate transient analysis and the construction of simulation of production models based on geologic and geophysical data
UR  - https://biblioteca.iapg.org.ar/ArchivosAdjuntos/Conexplor2022/Expl-y-sist-Petroleros/explora29.pdf
ER  -