Field Development Strategy Applied to a North African Field using Reservoir Simulation through an integrated Asset Team Work.

Abstract

Abstract An approach to an integrated asset team work to generate a field simulation static and dynamic model to carry out a field development plan revision is presented. A general workflow to assess this goal is developed. Structural and stratigraphic model, fine grid construction, facies characterization, properties distribution, geostatistical realizations to manage geo-static model are presented together with a complete reservoir simulation methodology. H Field is located in Murzuq Basin, SW Libya, in the middle of the southern part of NC186 block. The field was discovered by well H-01 in 2004. H Field is an elongated NW-SE paleo-high. Middle Ordovician sandstones are the main reservoir. Hawaz formation comprises a distinctive suite of facies associations representing a broad range of environments from low energy shelfal marine sediments deposited largely below storm wave base, through to sub-aerial delta plain channel environments. The depositional environment is characterized by a gently dipping shelf covered by epicontinental sea developing an extensive coastal plain area dissected by fluvial-tidal channels. Hawaz formation is subdivided into eight (8) units, three of which are the main reservoir (H4 to H6). The top layers (H1 to H3) are very tight with low quality petrophysical characteristics and they are considered for unconventional future development. Geological framework, fault and facies modeling was used in conjunction with observed dynamic performance to determine a representative distribution of reservoir properties. Upscaling process was not performed until the best fit model was achieved. The model dataset was based on twenty (20) existing wells (producers and injectors). Several simulation runs integrating history matching and interactive multidisciplinary work were performed before arriving to the final realization. Predictive runs to perform sensitivity checks on water injection scenarios and additional infill drilling were carried out, too. A combination of peripheral water-leg, structural-edge oil leg and internal line-drive water injection schemes was envisaged. Resistivity logs and RFT interpretation results were combined to define the water transition zone. The proposed revision of the Field Development Plan maximizes the ultimate recovery and requires the drilling of 40 producers and 20 water injectors to reach a 6-year duration production plateau rate of 25,000 bopd. Close work between interdisciplinary team members reduced time and increased the accuracy of the results. Additional wells drilled later on validated the structural and property distribution predicted by the model, as well as the individual productivity indixes. Recommendations for additional field data gathering were included in the final report to improve future model updates. Introduction and Objectives Reservoir modeling has been historically used as a tool to enhance Reservoir Management and to define long term Field Development Plans. Development decisions must be made despite uncertainties in well performance, subsurface response, equipment failure rate and oil demands. An iterative approach is necessary to identify best cases to improve planning.