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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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    Formation sampling optimization using fracture ready workflow (acoustics/borehole image) in unconventional tight sand reservoir. case study : ahnet field, Algeria
    (Society of Exploration Geophysicists, 2020) Kellal, Sara; Lamali, Rabah; Kecili, Kenza; Amor, Nasrine Bendali
    The formation evaluation of the unconventional tight sand reservoirs is challenging at different points of view, where several factors affect the recording and make their evaluation and the potential in place assessment hard to define. That’s why, the new technologies and customized workflows that are being applied in such reservoirs are greatly helping in decreasing the uncertainties encountered at different levels of the unconventional tight sand reservoirs lifecycle. One of the milestone steps is the formation fluids identification and sampling. In the past, the selection method of the intervals for formation fluids sampling using the MDT tool was based on conventional well logging analysis and more precisely on selecting intervals with high porosity compared to other intervals. However, this method has shown its limitations in tight reservoirs due to the low porosity and low permeability. For that reason, Schlumberger has established a new customized workflow known as ‘Fracture Ready Package’ in order to optimize formation fluids sampling program, which consists on an orientation to the characterization of natural fracturing which represents a major element in tight reservoirs cases. This methodology consists of the combination of acoustics (Sonic Scanner) and borehole image services to conduct a complete and detailed natural fractures characterization, namely: type of fracture (open fracture, semi open, closed cemented fracture) orientation and the exact location of the fracture and most important, analyze the continuity of the fracture far from well wall by analyzing anisotropy using sonic scanner tool