Improving Recovery of a Viscous Oil Using Optimized Emulsion Viscosity

Abstract

Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.

Emulsion Characterization of the Heavy Oil-Alkaline Water System in Alkaline Flooding Mechanism Investigation Using a Combination of Modified Bottle Test and Sandpack Flooding

“…As Bryan and Kantzas (2007) studied, the evolution process of emulsion generation is controlled by conditions of shear according to fluid velocity. Former researchers usually conducted the bottle test through mingling the alkaline solution and oil at certain volume ratios by shaking the bottle manually (Nelson et al, 1984) or through a tube shaker (Aminzadeh et al, 2016). Some other researchers used a blender or agitator to accomplish the task (Ding et al, 2010;Wang et al, 2010).…”

“…In addition, the quality of the final mixture is affected by operating conditions and oil properties. Among the series of heavy oil alkaline flooding performance studies, oils with viscosities lower than 3,000 cp were frequently studied (Ashrafizadeh et al, 2012;Dehghan et al, 2013;Aminzadeh et al, 2016), albeit the heavy oil viscosity in Canada can be as high as 10,000 cp (Bryan and Kantzas, 2007;Ashrafizadeh et al, 2012;Dong et al, 2012). For high viscous oil samples, bottle tests at temperature lower than 50 • C are tougher to manage and the poor fluidity of high viscous heavy oil reduces the chance of mixing with aqueous phase.…”

“…On the other hand, as a visualization method, the bottle test result is demonstrated by distribution of the emulsion phases based on density difference. A preceding phase distribution analysis was usually done through direct observation (Nelson et al, 1984;Bryan and Kantzas, 2007;Panthi and Mohanty, 2013;Aminzadeh et al, 2016;Baek et al, 2018). It is achieved by reading the volume scale marked on the container to determine the individual phase volume changes.…”

Visualization of Chemical Heavy Oil EOR Displacement Mechanisms in a 2D System

“…A polymer might be used to increase the viscosity of the displacing fluid and, in this fashion, reduce its mobility [1][2][3][4][5][6]. Surface-active agents such as surfactants, alkalines, and their combination might be used to improve oil recovery through the formation of emulsions [7][8][9]. The mechanisms linked to this process are ''emulsification & entrainment'' and ''emulsification & entrapment''.…”

“…A factor that has made it difficult to observe the performance of emulsification mechanisms is the type of model used for carrying out these flooding displacements. Most heavy oil recovery mechanisms observations in the literature have been made in linear cores or 1D systems which have limited available flow pathways [8,12,14]. For small cores or sand packs, it is possible for these limited previously flooded channels to be plugged off, and now access to new regions of the core will increase the pressure once again in the system, leading to an increase in oil production.…”