Determining the remaining spatial oil saturation distribution and current reservoir pressure distribution for a mature (water, solvent, CO2) flood is a cornerstone of reservoir management associated with improving sweep and selecting infill well locations. Decisions of this type are typically supported by reservoir flow simulation models that have been calibrated to the historical injection/production data.

In this paper, we present a material balance based approach to estimating remaining fluids in place as an alternative to using flow simulation. First we use the historical injection/production volumes to solve for streamlines and streamline derived pattern metrics such as well allocation factors and injector/producer well-pair reservoir volumes. Then we apply material balance on these volumes over time to estimate spatial fluid saturations and pressures existing at the end of history. Like reservoir simulation, the method accounts for changing well patterns through time, requires a 3D static geological model, and yields 3D saturation distributions of oil, water, and gas. However, unlike reservoir simulation the only calibration (history matching) required is the approximation of pore volumes and initial fluids in place of the patterns.

We present results for simple 2D models to illustrate the approach and compare to results from flow simulation. We then present a 3D pattern water/gas flood and the remaining oil and gas in place maps that are computed. The advantage of our method is that minimal history matching is required as historical injected/produced volumes are used explicitly; the disadvantage is that the resulting 3D saturation distributions are less detailed because the control volumes used for material balance are defined at the well-pair level which are many times larger than individual grid cells.

You can access this article if you purchase or spend a download.