After three years of production, questions arose about the ultimate reserves, opportunities for new wells and secondary recovery. Stochastic techniques were used to convert seismic acoustic impedance into a reservoir model. Care was taken to allow the data drive the model. The simulator results were very close to a history match, and only needed minor adjustments. The history match was compared to an earlier deterministic history match. Although both models were history matched, significant differences are apparent for the results of new wells, and for a possible water flood. These results increase our confidence in these methods to locate infill wells or plan new field developments.
This work describes reservoir characterization and flow simulation for a deep-water oil field in the Gulf of Mexico. The depositional environment is high-energy slope deposits of Miocene age, which have modest recovery because of high heterogeneity and low aquifer support. The paper will describe how attention to appropriate detail can result in a history match and production forecasts that inspire confidence in alternate field maintenance plans. It stresses the use of seismic, coupled with geostatistical methods, to define reservoir volumes and a level of heterogeneity critical to fluid flow. Revisions of the model for optimum history match were minor and data driven. The process, which we refer to as High Resolution Reservoir Characterization (HRRC), comes to grips with limited well, time-depth and core data in building the reservoir model. It is also aided by enhanced 3-D seismic data. In HRRC we also accommodate various uncertainties, especially those associated with the need to develop model detail below seismic resolution.
A depth structure map for the reservoir is shown in Figure 1. Salt movement influenced the oil accumulation and the sand deposition. The reservoir has been producing for 3 years from four wells. Those wells and 7 other exploration and production wells (targeting deeper formations), plus the seismic maps, were used to define the reservoir geometry. The seismic attribute in the map is the sum of acoustic impedance over the reservoir interval and is suggestive of pay distribution
From regional stratigraphy and log data, it was determined that the sands were deposited in the later stages of a submarine canyon fill. These capping sands were interpreted to be part of a leveed-channel complex in which channels migrated and most likely cut into existing deposits. The map in Figure 1 suggests the overall channel complex, but does not show any channel morphology. Figure 2 shows a seismic line that is strike to the flow direction. The canyon cut and capping reservoir sands are indicated. Reference 1 describes similar settings.
Four facies were selected for fine-scale modeling. They are Channel, Proximal Levee, Distal Levee and Slope. These divisions were based on log gamma ray character, on log porosity, on geologic reasoning and on seismic character. They were also chosen because they represented significant permeability regimes. The average properties of these facies are listed in Table 1.
