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The formation fracture gradient (FG) in deepwater environments is lower, compared to that in shallow water and onshore fields. Consequently, narrow margin drilling is generally a challenge in deepwater fields. The FG is sometimes different from the principal minimum horizontal stress (Shmin). The FG may be determined from the fracture initiation pressure (FIP) or from the pressure required for the fluid to leak off through conductive natural fractures. In contrast to the Shmin, the FIP is a function of wellbore trajectory. In this study, we present data from a deepwater gas field in Australia. The Shmin profile was calibrated against extended leak-off tests (XLOTs), microfrac, and injectivity tests in 12 offset wells using log-based poro-elastic and effective stress ratio (ESR) methodologies. We then constrained and calibrated the geomechanical model using a range of well logs, drilling data, and core experiments. The geomechanical model was used to calculate the FIP and its variation with borehole trajectory for a number of horizontal wells under initial and depleted conditions. The results show, for particular well trajectories, the mud weight window (MWW) is extremely narrow if the FG is considered to be equivalent to the FIP. In addition, Shmin tends to be low in reservoir sandstones, which will make the drilling of high-angled wells in the depleted zones challenging. If natural fractures exist in the reservoir, fluid may leak through the fractures in which conductivity could be enhanced by shear slip with a hole pressure less than both Shmin and FIP. We used the Mohr-Coulomb sliding criterion to identify the population of fractures in the reservoir most susceptible to shear slip. The results indicated that high-angled fractures that strike NE-SW may become critically stressed during drilling, meaning they are prone to slip and may lead to fluid losses with the bottomhole pressure (BHP) less than the FIP. The results of this study led to revisions to the planned well trajectories. We optimized the trajectories to take advantage of higher FIP (relative to Shmin) to reduce the risk of fluid losses into natural fractures. In addition, we considered depletion in the reservoirs for optimization. |
