The recovery mechanisms of high pressure and high temperature (HPHT) gas condensate reservoirs consist of pressure depletion, water encroachment, rock compaction and condensate banking near a well bore. The last two mechanisms require special treatments in a reservoir simulation model: the rock compaction leads to permeability reduction with declining pressure while the condensate banking requires small grids around a well. The condensate banking, which affects well productivity, was successfully simulated with a compositional simulator using radial local grid refinement within a Cartesian global grid system. A benchmark study was conducted to ensure the correctness of the local grid refinement.

An adaptive implicit method (AIM) was implemented which solves the local and global grids simultaneously. However, by making the local grids implicit, one avoided the time step restrictions which would otherwise occur due to their high throughput rates. In solving the linear equations which arose from the coupled local-global system, the grid ordering was found to be important. The optimal ordering proved to be that in which the local grids were placed before the global. This technique resulted in reduced computing time as well as robustness in dealing with field size models.

The solution technique was applied to a HPHT gas condensate prospect in the Central Graben region of the North Sea. This paper will address the recovery mechanisms regarding the rock compaction and the condensate banking. In addition, it will discuss the simulation of hydraulic fracturing as a means of improved recovery. Finally, it will present some experimental data that form the basis for input to the simulation model.

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