Publications Internationales

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Author: search.filters.author.Ganguli, Shib Sankar

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    Constraining maximum horizontal stress using wellbore breakouts A case study from the Ordovician tight reservoir of the northeastern Oued Mya Basin, Algeria
    (Society of Exploration Geophysicists, 2024) Baouche, Rafik; Sen, Souvik; Ganguli, Shib Sankar; Benmamar, Salim; Kumar, Prakash
    In this study, we interpret the maximum horizontal stress (SHmax) azimuth from the breakout positions of the wellbore and attempt to constrain the SHmax gradient based on the interpreted breakout width. A cumulative of 110 m of breakouts are deciphered within the Ordovician Hamra Quartzite interval of the Oued Mya Basin from a 138 m acoustic image log. These breakouts are ranked as A-Quality following the World Stress Map ranking guidelines. We infer a mean SHmax orientation of N28 E ± 8. Following the frictional faulting mechanism and stress polygon approach, measurement of the minimum horizontal stress (Shmin) from minifrac tests and observations of the compressive failures from the acoustic image log provide strong constraints on the SHmax magnitude in the reservoir interval in the absence of core-measured rock strength. Interpreted breakout widths exhibit a range between 32.6 and 90.81, which indicates a SHmax range of 24.4-34.7 MPa/km. The average breakout width of 62.58 translates to a narrower SHmax gradient range, varying between 27.2 and 31.2 MPa/km. The relative magnitudes of the principal stresses indicate a strong strike-slip tectonic stress state. Considering all the uncertainties, we infer a SHmax/Shmin ratio of 1.41-1.81 within the Ordovician interval.
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    Modeling In-situ tectonic stress state and maximum horizontal stress azimuth in the Central Algerian Sahara – A geomechanical study from El Agreb, El Gassi and Hassi Messaoud fields
    (Elsevier, 2021) Baouche, Rafik; Sen, Souvik; Chaouchi, Rabah; Ganguli, Shib Sankar
    Central Algerian Sahara hosts many prolific hydrocarbon accumulations in the Paleozoic successions. In this work a contemporary stress field of the Saharan platform has been evaluated using the dataset from recently drilled wells in El Agreb, El Gassi and Hassi Messaoud fields. A pore fluid pressure gradient of 0.56 PSI/feet is interpreted from the in-situ measurements in the Paleozoic reservoir units. Vertical stress (Sv) modeled from the bulk-density data indicates an average of 1.02 PSI/feet gradient. Rock elastic property-based approach is employed to model the magnitudes of minimum (Shmin) and maximum horizontal stress (SHmax) components, which were calibrated with leak off test/minifrac and breakout widths, respectively. Paleozoic stress profiles reveal Shmin/Sv range of 0.74–0.84, while SHmax/Sv varies between 1.1 and 1.33. Subsurface stress distribution indicates that the present-day stress field in the Saharan platform is principally strike-slip faulting (SHmax > Sv > Shmin). A cumulative 1490 m of B-D quality wellbore breakouts, inferred from the acoustic image logs, suggest a NW-SE/WNW-ESE SHmax orientation, which is parallel to the absolute African plate motion and Africa-Eurasia plate convergence direction, implying ridge push force to be the dominant contributor to the tectonic stress field. Mean SHmax orientation shows slightly anticlockwise rotation (126◦N to 144◦N) from south (El Agreb) to north (Hassi Messaoud field). Inferences are discussed regarding the fault slip potential and hydrocarbon reservoir development.
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    Petrophysical, geomechanical and depositional environment characterization of the Triassic TAGI reservoir from the Hassi Berkine South field, Berkine Basin, Southeastern Algeria
    (Elsevier, 2021) Baouche, Rafik; Sen, Souvik; Ganguli, Shib Sankar; Hadj Arab, Feriel
    An integrated knowledge of the sedimentological data, petrophysical and geomechanical characteristics significantly enhances the understanding of the reservoir properties, leading to a reliable subsurface modeling. This work presents a comprehensive reservoir assessment of the prolific Triassic Argilo-Gréseux Inférieur (TAGI) sandstones of the Hassi Berkine South (HBNS) field, Southeastern Algeria. The Lower Triassic producer appears to be laid down on the Late Devonian erosional surface (Hercynian unconformity) in a fluvial depositional system. Based on the sedimentary structures, a fluvial depositional environment is deciphered from cores. Lateral and vertical disposition of the channel and floodplain deposits from regional well log correlation infers a shift of depositional regime from braided in the SW to meandering in the NE direction. Two distinct reservoir rock types (RRT) are interpreted from core-based petrophysical assessment. RRT1 is composed of macro-megaporous medium to very coarse grained amalgamated channel sandstones and yields the best reservoir attributes, while the mesoporous fine grained RRT2 translates to impervious to poor reservoir quality. RRT1 channel sands are found to be laterally continuous, while the fine grained crevasse splay sands corresponding to RRT2 are laterally discontinuous, thus making them difficult to correlate field wide. Rock-mechanical property-based in-situ stress estimates suggested a normal to strike-slip transitional (Sv ≥ SHMax > Shmin) stress state in the TAGI Formation. Direct measurements indicate that the TAGI reservoir had an initial pore pressure gradient of 11.08 MPa/km and is presently depleted by 2.1–2.5 MPa. A stable depletion stress path value of 0.57 is inferred considering a pore pressure-minimum horizontal stress coupling. At the present-day depletion rate, normal faulting is unlikely to have happened at the TAGI reservoir level and it can be depleted by another 25 MPa before inducing any production-induced reservoir instabilities
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    Integrated reservoir characterization of the Paleozoic and Mesozoic sandstones of the El Ouar field, Algeria
    (Elsevier, 2020) Baouche, Rafik; Souvik, Sen; Debiane, Kahina; Ganguli, Shib Sankar
    This study presents the interpretation of depositional environment and petrophysical properties of Mesozoic and Paleozoic reservoirs from the south-eastern Berkine Basin, Algeria by integrating core analyses and geophysical logs. Sedimentary structures and ichnofossils identified from 100 m of recovered cores have been interpreted to characterize the depositional settings of the studied reservoirs. During the mid-late Triassic, fluvial to marginal marine processes deposited the TAGS and TAGI reservoirs, while the Palaeozoic megasequences are characterized by shallow marine reservoirs (tidal bars and foreshore deposits) interbedded with thin marine shales. Porosity and water saturation have been estimated from geophysical logs and calibrated with core-based laboratory measurements. An empirical relationship between core porosity and permeability has been established for the El Ouar area and the same has been employed to generate a continuous and confident permeability profile against the target reservoir formations. Petrophysical characterization indicates a higher porosity and permeability in Triassic and Carboniferous sandstones than the Devonian F6 members. Triassic TAGS and TAGI sandstones possess the highest reservoir qualities in the El Ouar field. The Thorium and Potassium content available from spectral gamma-ray data have been utilized to identify the clay types associated with various sandstone reservoirs (Illite in Triassic sandstone, Kaolinite in Carboniferous units, mixed clay and Th bearing heavy mineral dominance in Devonian units). The study will be helpful for understanding of hydrocarbon resource potential and subsequent production planning in the study area.
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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