We will discuss issues in developing a production-injection surface facility model to optimize both oil production and water injection strategy in a mature giant oil field. Surface facility modeling was done using commercially available software, which was coupled to Saudi Aramco's in-house reservoir simulator POWERS1 . Multiple integrated strategies for analyzing production can be considered with such models. In this paper, we evaluate a facility optimization perspective where many wells are rerouted between multiple gas-oil separation plants (GOSPs) to maintain adequate reservoir pressure to deliver required oil production volumes at the lowest operating cost. We also consider cases where the objective is to evaluate injection allocation strategies, which honors surface constraints, especially surface flow lines’ maximum operating pressure restrictions. Results presented in this paper include a subsurface reservoir coupled surface facility model where proposed strategies are designed to reroute wells from five existing GOSPs producing at high water cuts to two remaining GOSPs for production consolidation. Such strategy allows for an immediate cost savings, since it reduces the number of plants while at the same time producing the required volumes of oil, at reduced water cut, while at the same time maintaining reservoir sweep and recovery since wells which otherwise might have been shut-in are kept on active production. Simultaneously with the option of optimizing oil production, rerouting offers the opportunity to examine water disposal strategies since water can be injected near locations where there might be either a need for additional sweep or simply for reservoir pressure control and redistribution without compromising overall oil production.

We built a surface facility model consisting of five active GOSPs with a few hundred producers and injector (disposal) wells. The surface model is coupled to an over a million-cell reservoir model, containing a sub-set of all the wells available in the POWERS simulation model. Previous work had relied on describing exclusively the production system, leaving the injection system to be handled by POWERS’ well management rules and not subject to optimization or reconfiguration based on reservoir strategies. In this study, both the production and injection model have been constructed and calibrated using the latest available field data and history matched to field performance current at the time of calibration. Model calibration has been assisted by using automated scripts that transfer the relevant production and technical data from a corporate database to the individual model well files and which provide initial estimates for appropriate calibration parameter, such as productivity index, gradient curve matching or reservoir pressure at the time of a rate test, to current or historical field data. Those initial matches are later reviewed and validated on a well by well basis prior to use for prediction runs.

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