Mechanisms of Heavy Oil Recovery by Low Rate Waterflooding

Abstract

At the conclusion of primary heavy oil production, significant volumes of oil still remain in the reservoir under depleted reservoir pressure. Waterfloods are often considered for additional oil recovery. It is accepted that conventional oil waterflooding theory is not applicable for heavy oil. However, there is a lack of understanding of how waterfloods should perform in these reservoirs, particularly after water breakthrough. In this study, waterfloods were performed at multiple rates in cores containing heavy oil and connate water. In some cores, oil was initially free of solution gas, and waterfloods were a primary recovery process. In other cores, waterfloods were performed after primary production. Experiments were performed in linear systems for a high-viscosity oil (11,500 mPa·s at 23°C), at different injection rates. The influence of viscous and capillary forces is studied in primary vs. secondary recovery systems. A common misconception is that capillary forces are negligible in heavy oil; however, this work shows that these forces are significant, and that water imbibition after water breakthrough can lead to improved oil recovery in both primary and secondary waterfloods. Introduction The Canadian deposits of heavy oil and bitumen are some of the largest in the world. Recent estimates by the Alberta Energy and Utilities Board(1) suggest that this resource could exceed 270 billion m³ in Alberta alone, with a significant portion of this oil located in reservoirs where energy-intensive thermal operations will not be economic. Heavy oil is a special class of this unconventional oil, which has viscosity ranging from 50 - 50,000 mPa·s (cp) and low API gravity. Heavy oil reservoirs are often high-porosity, high-permeability, unconsolidated sand deposits. Permeability of the sand averages in the range of 3D, but oil does not flow easily because of its high viscosity(2). The oil may contain dissolved solution gas at initial conditions; thus, a fraction of the oil can be recovered through solution gas drive. Primary production can recover around 5% of the oil in place(1), leaving significant oil volumes in the reservoir for potential secondary recovery. Waterflooding is a common technique for secondary oil recovery in conventional oil reservoirs. In heavy oil systems, the extremely high oil viscosities lead to adverse mobility ratio conditions; thus, water will tend to "finger?? through the oil, and recoveries are expected to be extremely low(3,4). Despite the poor recoveries predicted theoretically, there have been numerous reports of heavy oil waterfloods performed in the literature(5-8). All of these studies report poor sweep efficiencies and low overall recovery. However, it is significant that in all cases some oil was still recovered, despite the highly adverse mobility ratios in the waterfloods.

Investigation into the Processes Responsible for Heavy Oil Recovery by Alkali-Surfactant Flooding

“…Despite the fact that some W/O emulsions were shown to have formed, and these are often indicative of an oil wet condition (Equation 1), the total water geometric mean T 2 values (T 2gm ) plotted in Figure 8 are still lower than the T 2gm of the original water-saturated core. This indicates that the rock was still water wet, and was verified through oil recovery via water imbibition 39 . Figure 9 shows the NMR spectra at the same four length locations after flooding one pore volume of DI AS solution through the core at a relatively high rate (0.51 m/day).…”

“…In fact, the optimal oil recoveries were around 70% of OOIP, and most floods actually recovered less oil. Under very low rate waterflooding for many pore volumes 3,39 , it is also possible to achieve similar residual oil saturation by allowing water imbibition to slowly sweep oil from the core. Therefore, as also observed previously by Jennings et al 24 , the improved oil response is one of improved sweep and accelerated oil production.…”

“…The interpretation of wettability from NMR spectra has been developed previously in the analysis of imbibition during heavy oil waterflooding 39,43 . Figure 13 shows the range of T 2 values for water located in various different physical locations in the porous media.…”

Analysis and Correlations of Viscous Fingering in Low-Tension Polymer Flooding in Heavy Oil Reservoirs

“…( and alkali, 8-14 low-rate waterflooding, 15 variable-rate waterflooding, 16 immiscible CO 2 flooding, 17 miscible CO 2 flooding, 18 and water-alternating-CO 2 injection. 10, 19,20 Among the suggested methods, a miscible gas injection process and, in particular, VAPEX suffers from low initial production rates, premature breakthrough, and possible formation damage due to in situ deasphalting.…”

Non-Newtonian Flow Characteristics of Heavy Oil in the Bohai Bay Oilfield: Experimental and Simulation Studies

“…Torabi et al [42] predicted heavy oil/water relative permeability by modified Corey-based correlations. Mai [43] reported that Johnson-Bossler-Naumann (JBN) method allowed for the calculation of apparent relative permeability curves that could be incorporated into reservoir simulators, and the effect of oil viscosity could be addressed through its effect on the apparent relative permeabilities calculated. Doorwar et al [44] considered that relative permeability functions needed to be modified to simulate unstable displacements with conventional simulators, and high viscosity ratio led to viscous fingering, which affected the observed relative permeability curves; they developed a lumped-finger model to modify multiphase flow equations and to yield pseudo relative permeability functions that accounted for viscous fingering.…”