Time-lapse seismic inversion for pressure and saturation in Foinaven field, west of Shetland

Christophe Ribeiro and Colin MacBeth present a new petro-elastic-based approach to independently estimate reservoir pressure and saturation from 4D seismic data obtained at BP’s Foinaven field, west of Shetland. In the last decade, the use of seismic monitoring (4D) has greatly increased, and oil companies have shown their commitment to this technology (Marsh et al., 2003; De Waal and Calvert, 2003), as confirmed by its more systematic application. Time-lapse seismic is now an integrated part of reservoir management strategy, and has proved its ability to improve reservoir understanding. In the past, the applications of seismic monitoring were predominantly focused on the tracking of fluid contacts and movements (i.e. gas-cap expansion, water sweep); discrimination between lithology and fluid effects; and identification of pressure compartment and reservoir connectivity. The growth of seismic reservoir monitoring has brought new technical challenges to the industry, in order to improve and enlarge the existing portfolio of this technology. In fact, the advance in acquisition (i.e. steerable streamers, full-wave field recording devices, permanent sensors), survey design (i.e. 4D dedicated acquisition), seismic processing (i.e. specific 4D workflow) and integration between contractors and oil companies (i.e. in-house processing and R&D teams) have improved the repeatability and quality of the data, and paved the way for new applications. Research has now moved towards the more quantitative aspects of 4D, attempting to estimate hydrocarbon-production-related changes directly from seismic data. However, in most cases, seismic amplitude changes are not only due to variation in fluid saturation, pore pressure, or even compaction, but to a combination of these effects. The goal of distinguishing between pore pressure and fluid saturation effects is a challenge in quantitative time-lapse seismic interpretation, and has been the subject of many papers. The separation of pressure and saturation effects has mainly been tackled by means of rock-physics-based techniques (Brevik, 1999; Tura and Lumley, 1999; Landrø, 2001), and recently engineering approaches using production, pressure and PVT data, have been developed (He et al., 2004; MacBeth et al., 2004). The independent estimation of pore pressure and fluid saturation, which are also two products from the reservoir flow simulation, allows a direct comparison between attributes derived from the seismic and engineering domains. These production attributes could be used in a 4D seismic history matching workflow in order to directly constrain the predictions from the fluid flow simulator with the seismically derived dynamic properties (Gosselin and Menezes, 2006; Stephen and MacBeth, 2006). Modifications of the reservoir model could also be made to improve the agreement between the flow simulation results and the seismically derived production estimates, and ultimately to increase reservoir performance and oil recovery.