Publications Internationales

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Author: search.filters.author.Baouche, RafikSubject: search.filters.subject.Pore pressure

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    Distribution of pore pressure and fracture pressure gradients in the paleozoic sediments of Takouazet field, Illizi basin, Algeria
    (Elsevier, 2020) Baouche, Rafik; Souvik, Sen; Boutaleb, Khadidja
    A comprehensive pore pressure and fracture gradient (PPFG) characterization is a basic requirement for subsurface geomechanical modeling. This study deploys indirect approaches to estimate subsurface pressure profiles in the Mesozoic and Paleozoic successions of eastern Illizi basin, Algeria. Amoco exponent has been modeled for pseudo density generation and overburden gradient has been deciphered from a composite density profile. PP calculated from sonic and resistivity logs have been calibrated and validated with direct downhole measurements. Results indicate normal pore pressure regime in the Mesozoic and Devonian sediments. Disequilibrium compaction induced abnormal pore pressure in Silurian marine shales with a maximum gradient of 12.7 PPG. Top of geopressure has been marked at Silurian top (2050m). Pore pressure drops sharply from Silurian to Ordovician sediments, across the glacial unconformity (2332 m). Fracture gradients have been interpreted by Eaton's Poisson's ratio based model and Mathews & Kelly's effective stress ratio based approach. Based on the vertical distribution of subsurface pressure, effective vertical stress, a safe mud window has been recommended for optimum drilling fluid design
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    Present day In-situ stress magnitude and orientation of horizontal stress components in the eastern Illizi basin, Algeria: A geomechanical modeling
    (Elsevier, 2020) Baouche, Rafik; Souvik, Sen; Boutaleb, Khadidja
    We analyzed drilling induced tensile fractures from resistivity image log data to ascertain the orientation of maximum horizontal stress (SH) from the eastern Illizi basin, Algeria. An average SH azimuth of 150�N (�10�) has been interpreted from B-quality induced fractures, as per world stress map guidelines. The overall NW-SE orientation of SH translates to the relative plate motion of the African and Eurasian plates. Vertical stress (Sv) gradient of 1.07 PSI/ft has been derived from density log. Pore pressure estimated from sonic slowness reveals overpressure in Silurian shale, deposited in a transgressive depositional environment, whereas Devonian and Ordovician hydrocarbon reservoirs have been seen to be normally pressured. Poroelastic strain model has been employed to quantify maximum and minimum horizontal stress (Sh) magnitudes. An effective stress ratio of 0.6, interpreted from leak-off test has also been used to model Sh. Using frictional faulting theory, upper limit of SH has been quantified. SH/Sv ratio of 1.04 (1.01–1.26) has been seen in the study area. Based on the relative stress magnitudes (SH >Sv >Sh), a present day strike-slip faulting regime has been inferred in the eastern Illizi basin, Algeria. Fault reactivation potential at reservoir level has been inferred from stress polygon analysis.
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    Characterization of pore pressure, fracture pressure, shear failure and itsimplications for drilling, wellbore stability and completion design–A casestudy from the Takouazetfield, Illizi Basin, Algeria
    (Elsevier, 2020) Baouche, Rafik; Souvik, Sen; Boutaleb, Khadidja
    We analyzed drilling induced tensile fractures from resistivity image log data to ascertain the orientation of maximum horizontal stress (SH) from the eastern Illizi basin, Algeria. An average SH azimuth of 150�N (� 10�) has been interpreted from B-quality induced fractures, as per world stress map guidelines. The overall NW-SE orientation of SH translates to the relative plate motion of the African and Eurasian plates. Vertical stress (Sv) gradient of 1.07 PSI/ft has been derived from density log. Pore pressure estimated from sonic slowness reveals overpressure in Silurian shale, deposited in a transgressive depositional environment, whereas Devonian and Ordovician hydrocarbon reservoirs have been seen to be normally pressured. Poroelastic strain model has been employed to quantify maximum and minimum horizontal stress (Sh) magnitudes. An effective stress ratio of 0.6, interpreted from leak-off test has also been used to model Sh. Using frictional faulting theory, upper limit of SH has been quantified. SH/Sv ratio of 1.04 (1.01–1.26) has been seen in the study area. Based on the relative stress magnitudes (SH > Sv > Sh), a present day strike-slip faulting regime has been inferred in the eastern Illizi basin, Algeria. Fault reactivation potential at reservoir level has been inferred from stress polygon analysis.
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    Pore pressure and in-situ stress magnitudes in the Bhiret Hammou hydrocarbon field, Berkine Basin, Algeria
    (Elsevier, 2020) Baouche, Rafik; Sen, Souvik; Ganguli, Shib Sankar
    A recently drilled exploratory well encompassing over 5 km of Mesozoic and Paleozoic sediments has been studied from the Bhiret Hammou field of the Berkine Basin, Algeria. Geophysical logs and downhole measurements have been integrated to ascertain rock strength, elastic properties, pore pressure and principal in-situ stress magnitudes. Vertical stress has an average 1.02 PSI/feet gradient in the studied field, as estimated from the density log. The Devonian shales are mildly over-pressured, while the Triassic and Carboniferous hydrocarbon reservoirs are in a hydrostatic pore pressure regime. Minimum and maximum horizontal stresses are quantified from a poroelastic strain model. The Sh gradient varies between 0.59 and 0.80 PSI/feet, whereas the SH gradient is interpreted as 0.86–1.26 PSI/feet. Based on the relative stress magnitudes (SH≥Sv>Sh), a present-day normal to strike-slip transitional tectonic regime is inferred