Resolving Uncertainty in Geomechanical Modeling for Hydro-Fracturing of Tight Sandstone in HPHT Geological Setting
Authors: Kumar Rajeev Ranjan , Zacharia Joseph , Subbiah Surej Kumar , Al Lawati Redha 
Published: September 2023

Development wells are being drilled targeting thick unconventional sandstone reservoir at 4,500m TVD with potential hydrocarbon accumulation, which requires hydrofracturing. Typical permeability ranges from 0.5md to 1.0md in good facies sandstone layers with bottomhole temperatures ranging from 290 °F to 340 °F and a formation pressure gradient of 0.65 psi/ft. Previous attempts at hydrofracturing in the field had not been desirable due to the undermining of the geological setting and related insitu stress behaviors. The present study has been carried out at three drilled wells with the objective of characterizing horizontal stresses, rock elastic properties, reservoir quality, and optimizing hydrofracturing design with each stage at different well locations to avoid water zones.

To reduce uncertainty in the geomechanics outputs to be used for hydrofracturing modeling, both far field and near wellbore acoustic measurements are inverted to estimate the minimum and maximum horizontal stress data. Available core data has been utilized to calibrate rock elastic and mechanical properties at downhole effective mean stress conditions. An anisotropic stress model has been built in shale layers overlying target sandstone layers. The TIH model has been used for sandstone layers with fractures as applicable. Individual tight and stress barriers have been identified inside sand packages to propose perforation intervals and initial stages considering stress contrast. An integrated solution using effective porosity, permeability, stress profile, Thomson parameters, and breakdown pressure helped to choose the minimum depth intervals for perforations.

Results show a strike slip fault regime at well locations with lateral variation in stress barriers within target sandstone where the minimum horizontal stress profile is close to the vertical stress and Young's modulus is relatively higher. The ratio of maximum horizontal stress to minimum horizontal stress is 1.07-1.35, depending on the stiffness of the layer. There is a clear stress barrier at the transition from the overlying shale formation to the sandstone formation. Estimated closure pressure in better reservoir quality layers ranges from 11,700 to 13,900psi. There are few layers that are relatively tight, with lower porosity having closure pressure in the range of 14,000psi −15,800psi. Target sweet spots have an estimated breakdown pressure in the range of 12500psi −14500psi. Preliminary fracturing simulations are run on various perforation depths as decided using geomechanical model and petrophysical parameters in 220-250m thickness package while keeping fractures away from the oil water contact. Temperature logging post main frac job is in close alignment with stress barriers predicted and frac geometry modeled with pressure history matching. This helped optimize stages accordingly in each well.

New workflow captured local geological setting, which helped to enhance 2X fracture proppant placement with incremental hydrocarbon production. Measured closure pressure and breakdown pressure are within 2% of estimated values for all stages completed in the three wells.