An important fraction of the reservoirs in the Outer Continental Shelf of the Gulf of Mexico is comprised of thin-bedded deposits from channel-levee systems. These reservoirs are particularly difficult to describe. Not only is their architecture complex but the quality of the reservoir is determined by connection and length of beds below the resolution of usual reflection data. Improved characterization is needed to improve development and production of these reservoirs. This study presents an integrated approach to build a geologically consistent reservoir model, based on the 8 sand reservoir in Northern Green Canyon block 18. The underlying idea of the construction of this model is that reservoir quality is influenced more by the internal architecture than by the statistical values of petrophysical parameters. Seismic interpretation and attribute extraction provided the reservoir geometry and stratigraphy. The structural framework and the limits of the reservoir have been determined, showing the preeminent role of salt and faults in the constitution of this reservoir. Seismic attributes are calibrated to extract areal information on reservoir architecture. Gross thickness and net thickness maps have been estimated using geostatistical methods. Lateral variations in the quality of the 8 sand and the definition zones with different average properties were inferred from geostatistical results. Lithofacies characterization from core showed that 3 facies could be used to describe the internal variability. The fine-scale heterogeneity is described in each zone from vertical facies distribution determined from wells. A truncated Gaussian sequential simulation was performed to reflect both the regional trend and the internal variability on a 150*150*1 ft grid. The major contribution of this work is to show the efficiency of this approach to describe complex reservoirs where the impact of internal variability is a major control of flow efficiency. This is especially valuable when the well information is scarce or not uniformly distributed. This model will be used for flow simulation and sensitivity analysis to improve the field description.

Understanding the internal organization of the Lower Pleistocene 8 Sand reservoir in the Green Canyon 18 field, Gulf of Mexico, helps to increase knowledge of the geology and the petrophysical properties, and hence contribute to production management in the area. Interpretation of log data from 29 wells, core and production data served to detail as much as possible a geological model destined for a future reservoir simulation. Core data showed that the main facies resulting from fine-grained turbidity currents is composed of alternating sand and shale layers, whose extension is assumed to be large. They correspond to levee and overbank deposits that are usually associated to channel systems. The high porosity values, coming from unconsolidated sediment, were associated to high horizontal permeability but generally low kv/kh ratio. The location of channel deposits was not obvious but thickness maps suggested that two main systems, with a northwest-southeast direction, contributed to the 8 Sand formation deposition. These two systems were not active at the same time and one of them was probably eroded by overlying formations. Spatial relationships between them remained unclear. Shingled stacking of the channel deposits resulted from lateral migration of narrow, meandering leveed channels in the mid part of the turbidite system. Then salt tectonics tilted turbidite deposits and led to the actual structure of the reservoir. The sedimentary analysis allowed the discrimination of three facies A, B and E, with given porosity and permeability values, that corresponded to channel, levee and overbank deposits. They were used to populate the reservoir model. Well correlation helped figure out the extension of these facies.

The move into deeper waters in the Gulf of Mexico has produced new opportunities for petroleum production, but it also has produced new challenges as different reservoir problems are encountered. This integrated reservoir characterization effort has provided useful information about the behavior and characteristics of a typical unconsolidated, overpressured, fine-grained, turbidite reservoir, which constitutes the majority of the reservoirs present in the Outer Continental Shelf of the Gulf of Mexico. Reservoirs in the Green Canyon 18 (GC 18) field constitute part of a turbidite package with reservoir quality typically increasing with depth. Characterization of the relatively shallow 8 reservoir had hitherto been hindered by the difficulty in resolving its complex architecture and stratigraphy. Furthermore, the combination of its unconsolidated rock matrix and abnormal pore pressure has resulted in severe production-induced compaction. The reservoir's complex geology had previously obfuscated the delineation of its hydrocarbon accumulation and determination of its different resource volumes. Geological and architectural alterations caused by post-accumulation salt tectonic activities had previously undermined the determination of the reservoir's active drive mechanisms and their chronology. Seismic interpretation has provided the reservoir geometry and topography. The reservoir stratigraphy has been defined using log, core and seismic data. With well data as pilot points, the spatial distribution of the reservoir properties has been defined using geostatistics. The resulting geological model was used to construct a dynamic flow model that matched historical production and pressure data.. The reservoir's pressure and production behavior indicates a dominant compaction drive mechanism. The results of this work show that the reservoir performance is influenced not only by the available drive energy, but also by the spatial distribution of the different facies relative to well locations. The study has delineated the hydrocarbon bearing reservoir, quantified the different resource categories as STOIIP/GIIP = 19.8/26.2 mmstb/Bscf, ultimate recovery = 9.92/16.01 mmstb/Bscf, and reserves (as of 9/2001) = 1.74/5.99 mmstb/Bscf of oil and gas, respectively. There does not appear to be significant benefit to infill drilling or enhanced recovery operations.