Proper reservoir surveillance and management are critical for all oilfield operations, but especially so for secondary and tertiary recovery processes. In older waterfloods developed several decades ago, one might be fortunate to have a single pressure falloff (PFO) test recorded per injection well, with multiple PFOs for any single injector being a rare occurrence. However, an increased focus on reservoir management has driven a growing appreciation of the value of time-lapse pressure transient analyses (PTA) to monitor various aspects of reservoir performance. Time-lapse interpretations often show changes as operations mature, and the new data helps to guide and reduce uncertainties inherent in earlier interpretations, maximizing the value of the data gathering and surveillance program.
The reservoir management programs for viscous oil waterfloods in India’s Barmer Basin include timelapse injection profiles and PFOs as key elements to help monitor flood front progression. However, the multiphase flow of fluids of different viscosities poses an interesting challenge for conventional PTA. For waterfloods with favorable mobility ratio (M), PFOs may look like a classic radial composite model, with a lower-mobility near-injector region exhibiting water properties and a higher-mobility outer region with oil properties. However, things change quite dramatically for unfavorable (end-point) mobility ratios as in the Barmer Basin waterfloods, where 10<M<300 or more. With unfavorable mobility ratios, a surprisingly large volume of injected water (and time) is required for even the near-injector wellbore region to approach "residual" oil saturation, and there is significant multiphase flow throughout the reservoir for the entire waterflood life.
A PFO from an unfavorable mobility ratio flood is more complex, no longer resembling a radial composite model, but one with a smooth "transition zone" of varying fluid saturations and mobilities extending all the way from injector to producer. Accurate PTA must account for this saturation profile via the use of actual fluid viscosities and relative permeability (relative mobility) curves. Simple PTA assuming a single effective permeability and a single fluid viscosity (either water, oil or some "average" viscosity) will produce misleading results.
With unfavorable mobility ratios, numerical PTA is required to provide reasonable estimates of reservoir properties and information on flood front progression from an injection well. Similar issues apply to PTA for mature high-watercut production wells. At a minimum, numerical analyses should be used to provide an appropriate anchor for simple PTA which uses oil and/or water viscosities.