Quantifying trapped residual oil in reservoir core material at the pore scale: Exploring the role of displacement rate, saturation history and wettability.

Abstract

Abstract At the conclusion of flooding into an oil- or gas-bearing reservoir, a significant fraction of the original hydrocarbon in place remains in the swept region as trapped residual phase. In addition to detemining the amount of trapped phase, the microscopic distribution within the pore space of the reservoir rock is important to gain a better understanding of recovery mechanisms, and for the design and implementation of improved or enhanced recovery processes. Despite the importance of the pore scale structure and distribution of residual oil, little quantitative information is currently available. This study presents a method to obtain this critical information. We utilize a new technique for imaging the pore-scale distribution of fluids in reservoir cores in three dimensions. The method allows reservoir core material to be imaged after flooding under different wettability conditions, saturation states and flooding rates. Oil recovery mechanisms are directly tested and the differences in the habitat of the residual fluids under different conditions are quantified. This paper describes the results of a range of flooding experiments performed on clastic and carbonate core material of varying complexity. Variations in the remaining hydrocarbon saturation are enumerated in-situ within the pore structure as flow rates, wettability and saturation history is varied. Detailed pore scale information of the residual oil saturation is reported. Introduction Although considerable attention has been paid to the subject of residual oil, the amount of quantitative experimental information on the structure of the residual oil phase in reservoir core material is limited. Attempts at modelling this phenomenon are difficult due to the inherent complexity of the physics of the waterflooding process; e.g., the need to incorporate realistic fluid:fluid and fluid:solid interactions including wettability. Most methods that attempt to quantify the residual oil phase use simplistic pore micromodels, or utilize destructive techniques (pore/blob casts) to infer mechanisms of the waterflood process (Craze, 1950, Chatzis, 1983). The amount of trapped phase in a reservoir rock after flooding and its microscopic distribution within the pore space is required to gain a better understanding of recovery mechanisms and for the design and implementation of improved or enhanced recovery processes. In this paper we attempt to address this issue through the application of a technique where one can image the pore scale distribution of different fluid phases in-situ within the pore space of reservoir cores. A key feature of this method is that experiments can be performed on the identical core under multiple states i.e. we perform the experiments on the same pore space in a non-destructive manner. In this way, the habitat of the residual fluids under varying conditions can be directly quantified, without ambiguity due to variations in the pore structure. In parallel to the role micromodels (Lenormand et al., 2003) have played in understanding the displacement mechanisms and complex multiphase flow properties of porous media in two dimensions, this development extends the concept of pore scale visualization of multiphase fluid flow to three dimensions. As the technique used is non-destructive, the detailed structure of the residual trapped phase can be readily described with repect to its location within the pore space. Additionally, the size distributions of residual oil blobs, features of blob shape and dimensions can be easily enumerated and compared under variable flooding conditions. These results provide important understanding of the habitat of the residual oil and a platform for the testing and calibration of pore scale modelling efforts for multiphase flow.