A wellbore stability model for hydrate bearing sediments

Abstract

Drilling in gas hydrate bearing sediments (HBS) presents an unquantified hazard to safe and cost effective drilling in deep water. A model is developed to simulate the stability of a wellbore drilled in a methane-hydrate bearing sedimentary formation. The model couples the thermodynamic stability of the hydrates in porous media to fluid and thermal transport and to mechanical deformation. The formation mechanical behaviour is modelled as poro-elasto-plastic, and the failure condition is represented by a Mohr Coulomb yield criterion. As hydrates in the pore space dissociate, the reduction in grain cementation is represented in the model by progressive loss of cohesion. The fluid flow and resulting pore pressure distribution is modelled using a single-phase Darcy flow model. The effect of the varying pore pressure on the stress field is accounted for in the stability analysis. The pore fluid composition is assumed to be water containing 3.5% NaCl, with methane as the hydrate-forming gas. A lookup table based on thermodynamic calculations is used to simulate the change in hydrate stability as a result of variation in the system pressure and temperature associated with drilling a wellbore using a drilling fluid several degrees hotter than ambient. If at a certain temperature, the system pressure is below that in the phase diagram, hydrates will draw in heat and dissociate. Boyle's Law for an ideal gas is used to equilibrate pressures after the dissociation step. The remaining amount of hydrates in the pore space is calculated accordingly, and the change in porosity is updated. The modified cohesion corresponding to the remaining percentage of hydrates is then fed back into the model. The developed numerical model is found to be very useful in understanding the behaviour and predict the responses of HBS to processes associated with overbalance drilling of a wellbore.