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Subject: search.filters.subject.In-situ stresses

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    Geomechanical modeling to assess the injection-induced fracture slip-potential and subsurface stability of the Cambro-Ordovician reservoirs of Hassi Terfa field, Algeria
    (Elsevier Ltd, 2024) Benayad, Soumya; Sen, Souvik; Baouche, Rafik; Mitra, Sourav; Chaouchi, Rabah
    The in-situ stress state and the distribution of the critically stressed fractures have significant implications on optimum wellbore placement, production enhancement, fluid injection, and induced seismicity which largely influence the reservoir management strategies. This study presents a comprehensive geomechanical modeling to infer the likelihood of shear slippage of the optimally oriented weak planes in response to water injection in the deep Paleozoic oil reservoirs from the Hassi Terfa field, central Algerian Sahara. The ‘B-quality’ compressive failures, i.e., breakouts from the acoustic image log indicate the maximum horizontal stress azimuth as N114°E. The inferred in-situ stress magnitudes indicate a strike-slip tectonic regime in the study area. The reservoir is generally tight (porosity <8 %, permeability <0.4 mD) due to extensive silica cementation, however pre-existing closed to partially open natural fractures of variable geometries are identified on cores, thin sections, and image logs. The stress-based slip assessment indicates that none of the fracture geometries is critically stressed and hydraulically conductive at the initial reservoir stress state. The onset of slip on the critically oriented vertical fractures can initiate at 1200 psi of fluid injection at the reservoir level of ∼3500 m. The E-W to EES-WWN oriented fractures, parallel to the maximum horizontal stress azimuth, have a higher likelihood of being critically stressed during injection and therefore can contribute to the permeability enhancement. We restrict the practical injection threshold at 3000 psi, which can create tensile failures on the shale caprocks. We infer that the NE-SW and NNE-SSW striking, steeply dipping fractures and regional faults being perpendicular or at high angles to the regional maximum horizontal stress azimuth, are the most stable ones and therefore, less likely to slip within the practical injection limit.
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    Assessment of reservoir stress state and its implications for Paleozoic tight oil reservoir development in the Oued Mya Basin, northeastern Algerian Sahara
    (Elsevier, 2023) Baouche, Rafik; Shib, Sankar Ganguli; Senc, Souvik; Radwan, Ahmed
    The Cambrian and Ordovician clastic reservoirs of the Oued Mya Basin exhibit significant vertical thickness and extensive lateral continuity, despite being tight. These reservoir intervals have not been properly understood yet in terms of in-situ stress distribution and pore pressure behaviour. The main objectives were to infer the reservoir stress state and draw implications for the tight oil reservoir development based on the geomechanical analyses. We interpreted breakouts from a cumulative 1485 m of acoustic image logs and interpreted a NW-SE SHMax orientation (N125°E-N147°E) in the Oued Mya Basin. The inferred breakouts were of B-D quality as per the World Stress Map ranking criteria. Both the reservoirs have a pore pressure gradient of 13.58-13.77 MPa/km, while the minifrac data infers a reservoir Shmin gradient of 17.3-19.2 MPa/km. Based on the breakout widths, we estimated the SHMax gradient as 23.8-26.5 MPa/km. Following the univariate regression analyses to identify various influencing parameters on horizontal stress magnitudes, we proposed multiple linear regression (MLR) models to predict the Shmin and SHMax based on pore pressure, Sv, Poisson's ratio, and Young's modulus. Results indicate that Sv influences the horizontal stress estimates significantly more as compared to the other influencing variables. The predicted Shmin and SHMax values are in good agreement (goodness of fit as R2 = 0.976 and 0.994) with the measured data. The newly proposed MLR equations can be utilized in absence of subsurface validation data. A strike-slip faulting reservoir stress state is concluded from stress polygon analysis. An optimum drilling strategy is discussed based on the observed wellbore failures. We recommended the drilling fluid pressure to be increased by 8 MPa and 14 MPa to avoid breakouts against the Ordovician and Cambrian reservoirs respectively, however, that may incur tensile fractures which do not have a considerable effect on wellbore stability while drilling. Based on this work, horizontal well trajectory along NE-SW (i.e., parallel to Shmin), together with oriented perforations aligned parallel to inferred SHMax direction is recommended. The potential fracture reactivation risks during reservoir pressurization are evaluated and discussed.
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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.