For a safe and efficient reservoir development, it is important to understand if, how, when and where faulting and fracturing will occur as a function of reservoir production or stimulation operations, or in case of a dumpflood or an internal blow-out situation. This paper describes 1) the making of a numerical geomechanical model to achieve this understanding, 2) the uncertainty in geomechanical model results, and 3) how the model results were applied in operational decisions for production and on reservoir fluid containment. The case study presented here is one of deep-gas production from stacked thin (few meters) sandstone reservoirs vertically separated by shale layers and laterally cut by steeply-dipping sealing normal faults, with pore pressure differences of several MPa across the faults in many sand-shale and sand-sand juxtapositions. We calculated the effective normal stress (σn) and maximum shear stress (τmax) along the faults and in the country rock as a function of pore pressure changes documented in the field development plan. The σn - τmax data were compared with fault slip and fracture-opening criteria based on Mohr-Coulomb frictional slip and tensile fracturing laws using fault cohesion, fault-friction-angle, and tensile strength as input. The geomechanical model results indicate that the current operational criterion of a maximum pore pressure difference of 7 MPa across the faults can be increased to 10 MPa without creating shear failure or tensile fracturing. This would lead to greater operational flexibility, cost reduction (less wells), and accelerated yet safe production.


Article metrics loading...

Loading full text...

Full text loading...

This is a required field
Please enter a valid email address
Approval was a Success
Invalid data
An Error Occurred
Approval was partially successful, following selected items could not be processed due to error