Petrophysical and geomechanical characterization of the Late Cretaceous limestone reservoirs from the Southeastern Constantine Basin, Algeria

Abstract

We have characterized the petrophysical and geomechanical properties of the Late Cretaceous Turonian and Cenomanian carbonate reservoirs from the southeast Constantine Basin, northern Algeria. In general, Turonian carbonates exhibit a wide range of porosities (2%–15%) and permeabilities (0.001–10 mD), whereas the Cenomanian reservoir appears to be very tight (<6% porosity and <0.1 mD permeability). Based on their storage and hydraulic flow characteristics, these carbonates were classified into two distinct reservoir rock types (RRT): RRT-I is hosted by nano- to microporosities that displays poor reservoir qualities compared to the RRT-II, consisting of mesoporous Turonian intervals (>10% porosity and 0.5–10 mD permeability). The reservoir pore-pressure gradient is interpreted to be a little above the hydrostatic (0.51 psi/ft), whereas the minimum horizontal stress ([Formula: see text]) has a 0.72 psi/ft gradient. In situ stress analysis establishes a dominant strike-slip tectonic stress field in the basin. Shale intercalations associated with the carbonate facies are characterized by comparatively high failure pressure that can lead to wellbore failures, which may be avoided considering the recommended minimum drilling mud weight as obtained from the rock failure criterion. Extensive wellbore breakouts (C-quality) were observed in the acoustic image logs recorded in the studied reservoir intervals, inferring a mean maximum horizontal stress azimuth of 350°N. We recommend that deviated wells in the direction of the interpreted [Formula: see text] orientation (approximately east–west) using hydraulic fracturing can be useful to attain optimum wellbore stability and effective permeability enhancement. Our findings have significant implications for enhanced production within the tight carbonate reservoirs situated in a strike-slip domain.