Numerical reservoir simulation is often accompanied by difficulties with history matching, especially as regards history matching of individual wells. On the one hand, the problems are explained by amount and quality of initial information on a reservoir. On the other hand, these problems pertain to numerical realization of a simulator applied, in particular, to well bore zone modeling. The expertise gained in reservoir simulation often demonstrates the excess of calculated watercut values over the actual ones. Similar situation occurs while performing an analytical solution of the well bore zone displacement problem. Therefore, it appears to be necessary to assess quality of reservoir simulation in terminology of well-cell fluid distribution. In order to solve the given problem, a special inverse well bore zone modeling problem has been formulated, which accounts for actual development data and numerical results of reservoir simulation obtained using the development-target model created. The uncertainty analysis is based on Monte Carlo method, the objective function is minimized using Nelder-Mead method. The key adjusted parameters are porosity, absolute & relative permeability, capillary pressure. At solving inverse problems, the filtration features become apparent, which relate to combined action of capillary, gravity and elastic forces. It is noted how important is to get a proper description of a well bore zone filtration process. Variance in results obtained with/without capillary pressures is shown. Also, it is demonstrated that the reservoir simulation models with relatively simple filtration pattern but with account for capillary, gravity and elastic forces can reproduce the complex watercut dynamics of the wells under study. The suggested method has been tested on one of Orenburg oilfields. Application of the given approach allows to analyze and adjust the numerical models on a new level, and avoid multiple reservoir simulation runs that distort a physical essence of actual displacement.


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