Reservoir Description by Inverse Modeling: Application to EVGSAU Field

Abstract

Abstract The major problem of conventional geostatistical reservoir characterization by conditional simulation is that none of the equiprobable realizations (permeability and porosity) generated may fit the field data when used in a reservoir simulation. A recently developed inverse modeling procedure was tested on the CO2-foam pilot area of the East Vacuum Grayburg/San Andres Unit (EVGSAU). The modeling procedure estimated reservoir properties through an automatic and multi-well history matching algorithm. The reservoir parameters, which were estimated by solving an inverse problem, were permeability distribution, average relative permeability and capillary pressure curves, reservoir engineering parameters such as the productivity or injectivity index at the wells, and effective injection rates. All parameters were estimated at reservoir scale in this approach. A least-square error objective function was minimized by using the simulated annealing method (SAM). The field data matched were the oil, gas, and water productions at each well. The convergence of this new algorithm is guaranteed by the use of SAM, and the permeability distribution generated is conditioned to the dynamic field data. Additionally, for the first time, reservoir engineering parameters were estimated at reservoir scale. At each iteration, a limited number of reservoir parameters were adjusted. Then, a black oil reservoir simulator was used to evaluate the impact of these new parameters on the field production data. Finally, after comparing the simulated production curves to the field data, a decision was made to keep or reject the altered parameters tested. A reliable, efficient computer code was developed to estimate reservoir properties by automatic history matching. The algorithm was tested on the EVGSAU for the waterflood period (1980–1985). After optimization, a good match was obtained for all the dynamic field data (production of oil, gas, and water) at all the wells located in the pilot area of the EVGSAU. The resulting large-scale reservoir description was then used to simulate CO2 injection after 1985. The pilot region production history from 1986–1991 was suitably matched using the waterflood reservoir description.