Many heavy oil reservoirs contain oil that has some limited mobility under reservoir conditions. In these reservoirs, a small fraction of the oil-in-place can be recovered using the internal reservoir energy through heavy oil solution gas drive (primary production). An integral part of this process is the so-called 'foamy oil mechanism', whereby oil is produced as a gas-in-oil dispersion. At the end of primary production, the bulk of the oil is still in place, while the natural energy of the reservoir has been depleted. This remaining oil is still mostly continuous and presents a valuable target for further recovery. Many of these reservoirs are relatively small or thin, or may be contacted by overlying gas or underlying water. As such, they are poor candidates for thermal oil recovery methods, so any additional oil recovery after primary production must be non-thermal. In this work, we present experimental results of foamy oil depletion at two different length scales and varying depletion rates. Tests were conducted in the absence of sand production, and the results from the depletion experiments are interpreted in terms of viscous forces. At the conclusion of primary recovery, the potential for further non-thermal exploitation of these reservoirs is explored. Results for waterflooding and chemical flooding are presented, demonstrating the viability of these techniques for heavy oil EOR. Several displacement mechanisms are identified through the secondary and tertiary processes that contribute to significant (although potentially slow) incremental recovery of heavy oil. Introduction Many countries have heavy oil reservoirs. Canada and Venezuela in particular contain some of the largest heavy oil and bitumen resources in the world. Rising energy demands, coupled with a decline in conventional oil reserves, has led to increased interest in heavy oil recovery in recent years. The size of these heavy oil deposits is considerable, and with volatile crude oil prices making it difficult to produce from some higher viscosity bitumen reservoirs, production of heavy oil could potentially be very important in years to come. Understanding the mechanisms by which heavy oil can be displaced in reservoirs is crucial to the successful recovery of this resource base. Heavy oil can be defined as a class of oils with viscosity ranging from 50 mPa.s up to around 50,000 mPa.s. This oil has limited mobility under reservoir temperature and pressure, and Darcy's Law predicts that the oil can flow slowly under high applied pressure gradients. However, it has been observed that in these reservoirs, solution gas drive leads to significantly higher rates and recoveries than what was expected by conventional understanding of gas-oil relative permeability behaviour(1). This behaviour, first reported in Canadian heavy oil, has since been observed in many other reservoirs around the world including South America, China and Albania. Investigations into the causes of this abnormal, but fortuitous, primary production response have been the focus of many publications in the past 25 years. The recovery from primary production in heavy oil reservoirs may be as high as 20%(2), but is usually lower.

Many countries in the world contain significant heavy oil deposits. In reservoirs with viscosity over several hundred mPa's, waterflooding is not expected to be successful due to the extremely high oil viscosity. However, in many smaller, thinner reservoirs, or reservoirs at the conclusion of cold production, thermal enhanced oil recovery methods will not be economic. Waterfloods are relatively inexpensive and easy to control; therefore, they will still often be employed in high viscosity heavy oil fields. This paper presents experimental findings of waterflooding in laboratory sandpacks for two high viscosity heavy oils of 4,650 mPa.s and 11,500 mPa.s at varying water injection rates. The results of this work show that capillary forces, which are often neglected due to the high oil viscosity, are important even in heavy oil systems. At low injection rates, water imbibition can be used to stabilize the waterflood and improve oil recovery. Waterflooding can therefore be a viable non-thermal enhanced oil recovery technology, even in fields with very high oil viscosity. Introduction Although conventional oil reserves are declining in many countries, the global energy demand is still increasing. As a result, the industry focus is now shifting towards unconventional oil resources, such as the oil sands in countries like Canada and Venezuela. The size of this resource base is immense, but the production of high viscosity crude oil carries its own unique challenges. Heavy oil is a special class of this unconventional oil, and has viscosities ranging from 50 to 50,000 mPa.s. Heavy oil reservoirs are often found in highly porous, highly permeable, unconsolidated sand deposits. At reservoir conditions, the oil may contain dissolved solution gas; thus, some oil can be initially recovered using the energy from heavy oil solution gas drive. At the end of primary production, however, a significant amount of oil still exists for potential secondary recovery. Many of these reservoirs are small and thin or were disturbed during primary production, making them poor candidates for expensive thermal enhanced oil recovery strategies. In times of uncertain commodity pricing, it is beneficial to examine the potential for relatively inexpensive, non-thermal oil recovery techniques. Waterflooding is often employed, at least initially, in heavy oil reservoirs, both along with or after primary recovery in order to re-pressurize the reservoir and displace oil to producing wells. In these applications, it is very important to understand the forces that are present in the reservoir and how they can be used to properly design the waterflood. Specifically, proper design and maintenance of waterfloods requires comprehension of how viscous oil can be displaced by water, and how oil recovery can be optimized. This work presents the results for water injection into laboratory sandpacks containing gas-free heavy oil of varying viscosity. The responses for different waterfloods are compared in order to investigate the mechanisms by which heavy oil can be recovered by water injection. Theory Waterflooding of oil reservoirs is a well-recognized technique for oil recovery after primary production. In conventional oil, waterflooding theory has been well documented(1).

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.