Extension and development of low permeability reservoirs in Campo Indio Field, Magallanes Formation (Late Maastrichtian - Danian), Austral Basin, ArgentinaCampo Indio Field is located in Santa Cruz province, 140 km northwest of the City of Río Gallegos. It is located in the slope area of the Austral Basin where different types of traps are present in both Cretaceous and Tertiary reservoirs. The accumulation of gas and condensate found within the M1 reservoir of the Lower Member of Magallanes Fm. that was discovered in 2001 with well CI.a-23, reports an accumulated production of 3658 MMm3 of gas. The extensions to the north and east were relegated since advanced wells showed poor reservoir conditions that yield to initial productivities below the commerciality threshold (10 to 30 Mm3/d).In the northeast sector of the field, M1 reservoir detaches from the traditional frame of Tight sands, showing low content of clay minerals and very good porosity values (~ 20-28%) but permeability ranging from 0.03 to 1 mD, which makes conventional development impossible. The trap is purely stratigraphic limited by lateral changes of facies in the reservoir and by the erosion of the "D4" unconformity (Post-Danian). The 3D seismic was crucial in order to identify the play, which has an amplitude anomaly that also shows an AVO class III effect. Production from the western sector began in 2002, close to the associated accumulation of Campo Boleadoras Field, where permeability ranges from 10 to 200 mD and yields to high initial productivity of the wells (150 to 400 Mm3/d of gas and 18 m3/d condensed).Petrophysical characterization showed that granulometric changes within the reservoir is the main driver affecting permeability. The arcosic-glauconitic composition of the sandstones together with the low clay content makes classic analysis techniques unsuitable for the detection of netpay and low connate waters salinity (8000 ppm ClNa) making Sw calculations uncertain, which is estimated higher than 60% and of irreducible nature due to high capillarity effects.The integrated analysis of the reservoir and the drilling of stepout wells led to a development strategy that involved horizontal and deviated "monobore" wells with fractures of > 3000 sand saks per stage. This in time allowed commercialization through 25 wells drilled since December 2016, which implies an increase in production of 3000 Mm3/d.