Summary Canada contains vast reserves of heavy oil and bitumen. Viscosity determination is key to the successful recovery of this oil, and low-field nuclear magnetic resonance (NMR) shows great potential as a tool for estimating this property. An NMR viscosity correlation previously had been developed that is valid for order-of-magnitude estimates over a wide range of viscosities and temperatures. This correlation was built phenomenologically, using experiments relating NMR spectra to viscosity. The present work details a more thorough investigation into oil viscosity and NMR, thus providing a theoretical justification for the proposed correlation. A novel tuning procedure is also presented, whereby the correlation is fitted using the Arrhenius relationship to improve the NMR viscosity estimates for single oils at multiple temperatures. Tuning allows for NMR to be potentially used in observation wells to monitor thermal enhanced oil recovery (EOR) projects or online to monitor the viscosity of produced-fluid streams as they cool. Introduction With approximately 400 million m3 of oil in place, the Canadian deposits of heavy oil and bitumen are some of the most vast oil resources in the world.1Heavy oil and bitumen are characterized by high densities and viscosities, which is a major obstacle to their recovery. The waning of conventional-oil reserves in Canada, coupled with increasing worldwide demand for oil, has forced the industry focus to shift rapidly to the exploitation of these heavy-oil and bitumen reserves. The most important physical property of heavy oil that affects its recovery is its viscosity.1 This parameter dictates both the economics and the technical chance of success for any chosen recovery scheme. As a result, oil viscosity is often directly related to recoverable reserves estimates.2 Unfortunately, laboratory measurements of oil viscosity become progressively more difficult to obtain as viscosity increases.3 The oil that has been removed from the core also may have been physically altered during sampling and transport. Thus, the viscosity at reservoir conditions may be different from the value obtained later from the laboratory.2 In light of the shortcomings of conventional viscosity measurements, low-field NMR is considered as an alternative for estimating heavy-oil and bitumen viscosity. The main appeal of NMR as a tool for assessing reservoir-fluid viscosities and phase volumes is that the measured signal comes only from hydrogen, which is present in both oil and water found in hydrocarbon reservoirs.4,5 Most of the low-field NMR applications in the petroleum industry have been inconventional oil, contained in sandstone reservoirs.6 To use low-field NMR technology in heavy-oil and bitumen formations like the ones present in Alberta, new methods of interpretation are required. The eventual goal for using NMR to estimate viscosity is to make these predictions in the field through logs. Currently, research toward this goal is conducted in the laboratory. In previous work,7-9 an oil-viscosity correlation was presented that is capable of providing viscosity predictions for samples with viscosities less than 1 mPa×s to more than 3 000 000 mPa×s. This is a wider range than any other viscosity correlation presented in the literature.10–15 The correlation is only order-of-magnitude accurate but still could be valuable for applications on a logging tool, where the goal would be to determine viscosity variations with depth or areal location in a reservoir. The theoretical justification behind the NMR correlation is given in this work, along with a procedure for tuning the correlation to improve the viscosity predictions for individual oils as a function of temperature. Low-field NMR experiments are simple to perform and nondestructive. The same test also can be run by different technicians to yield the same results, which is a concern for conventional viscosity tests.3 In this manner, a properly calibrated NMR model for viscosity can be a very accurate and useful tool for predicting heavy-oil and bitumen viscosity at different temperatures.

This study presents the results of laboratory core studies investigating the recovery mechanisms of alkali-surfactant flooding in heavy oil reservoirs. Specifically, mixtures of water and alkali-surfactant systems have been injected into cores containing heavy oil (11 000 mPa×s and 15 000 mPa×s). Salinity is varied in order to generate oil-in-water vs. water-in-oil emulsion systems, and the effects of generating different emulsions are compared. The application of this work is for the many heavy oil reservoirs in countries such as Canada and Venezuela containing viscous oil that still has some limited mobility under reservoir conditions. Alkali-surfactant (AS) flooding has considerable potential for non-thermal oil recovery after primary production. Experiments were performed on cores with varying permeability, at different AS injection rates. All tests were performed on gas-free oil systems. The response from direct injection of AS systems is compared to AS injection after waterflooding. Pressure and oil recovery information is obtained from core floods, and these results are interpreted based on a semi-theoretical framework obtained from phase behavior and bulk liquid studies. It is demonstrated that both oil-in-water and water-in-oil emulsions can lead to the recovery of additional oil. Alkali-surfactant flooding is already an established technique in conventional oil reservoirs, whereby enhanced oil recovery is a result of reduced trapping of oil due to the lowered oil/water interfacial tension. In addition, the injection of these chemicals may lead to the formation of emulsions, as has been documented by previous researchers. In our work, we demonstrate that in heavy oil systems, emulsion formation is a necessary requirement for the production of heavy oil. When these emulsions form, AS injection can lead to considerable improvements in the flooding response, even without the addition of polymers to stabilize the flood. Introduction Several countries in the world, notably Canada and Venezuela, contain massive resources of unconventional heavy oil and and bitumen. With issues of resource stability and rising oil prices, international interest is now shifting rapidly towards Canada's oil sands. The oil sands are characterized as unconsolidated, high porosity and high permeability reservoirs. While ease of flow is therefore not a significant concern, the single biggest obstacle to successful recovery from the oil sands is the high oil viscosity. Heavy oil reservoirs are a special subset of the oil sands, whereby the oil viscosity at reservoir temperature and pressure varies on the order of 50 - 50 000 mPa×s (cP). While this oil is still very viscous, it does have some limited mobility at resevoir conditions. As much as 20% of the oil may be recovered by solution gas drive1, but in many cases the recovery is much lower. At the end of primary production, significant oil still remains in the reservoir, but the reservoir energy has now been depleted. This is the target for enhanced heavy oil recovery. In order to recover additional heavy oil after primary production, a fluid usually has to be injected in order to displace oil to the production wells. However, mobility ratio concerns dominate displacement of viscous oil, and most EOR processes focus on reduction of the oil viscosity or improvement in the mobility ratio. Unfortunately, many of the heavy oil reservoirs in Canada are relatively small and thin, making them poor candidates for expensive thermal processes. Ideally, the displacement mobility ratio should be improved in an inexpensive (i.e. non-thermal) fashion. This work investigates the potential for alkali-surfactant flooding to be used for enhanced heavy oil recovery. The injection of alkalis and/or surfactants into oil reservoirs is not a new technology. As early as in the 1920's, Nutting proposed the injection of alkaline solution into reservoirs for oil recovery2. The injection of a combination of alkali and surfactant was discussed in the 1950's by Reisberg and Doscher3. Since then, chemical injection (alkali and/or surfactant) has become an accepted enhanced oil recovery methodology in many conventional oil applications.

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.

Alkali-surfactant flooding is an established enhanced oil recovery technique in conventional oil reservoirs, whereby the injected chemical lowers the oil/water interfacial tension, leading to reduced trapping of oil ganglia. In the past, there have been some studies of alkali and alkali-surfactant flooding of heavy oil systems as well, and it has been observed that chemical injection can lead to improved oil recovery. The heavy oil recovery mechanism proposed in this work is the creation of oil-in-water emulsions, which may form under conditions of low interfacial tension and shear due to flow through rock pores. Oil may either be produced in the water (emulsification and entrainment) or the droplets may coalesce or plug the rock pores, leading to improved sweep efficiency (emulsification and entrapment). Both of these mechanisms are investigated in laboratory systems of varying rock permeability, using a heavy oil with a viscosity of 11,500 mPa.s. When oil-in-water emulsions form, the oil recovery can be improved significantly, even without the addition of polymer for mobility control. The effect of permeability and varying injection rates are considered, to understand how different ranges of shear affect the efficiency of these emulsion systems. Introduction Several countries in the world, notably Canada and Venezuela, contain significant deposits of heavy oil and bitumen. As Canadian conventional oil reserves continue to decline, the industry interest is now shifting rapidly towards the recovery of this unconventional crude. The immensity of this resource base is exciting, but heavy oil reservoirs pose unique challenges when designing recovery strategies. The Canadian oil sands are unconsolidated, high porosity and high permeability reservoirs. Ease of flow is therefore not an issue, as it is in many conventional oil reservoirs. Rather, the single biggest impediment to the successful recovery of heavy oil and bitumen is the high oil viscosity. Heavy oil reservoirs are a special subset of our oil sands, whereby the oil viscosity at reservoir temperature varies from around 50 mPa.s up to around 50,000 mPa.s. At reservoir conditions, the oil requires high pressure draw downs in order for it to flow even through the permeable sands, after which point the reservoir has been depleted of all of its natural energy. In order to recover additional heavy oil, energy has to be injected into the reservoir. Often, this takes the form of a fluid that displaces the oil, meaning that the oil must be made to flow to production wells. Most improved/enhanced oil recovery schemes focus on reduction of the oil viscosity through the application of heat or miscible solvents. However, many of the Canadian heavy oil reservoirs are relatively small and thin, and have been disturbed to an unknown extent during primary production. Therefore, the development of injection strategies that are not energy intensive (i.e. non-thermal) and easy to control will be of considerable benefit to heavy oil producers. In this work, alkali-surfactant solution is investigated as a potential non-thermal injection fluid. It is demonstrated that through the injection of low concentrations of alkali and preformed surfactant solution, oil recovery can be increased significantly above that of waterflooding.

Solvent-based processes are often used as potential recovery agents in bitumen systems, with and without the addition of heat to the solvent. Solvents can sometimes be applied as a liquid phase, during SAGD start-up operations or processes aimed at developing injectivity into the oil. Light hydrocarbon liquids are traditionally tested for this application. Solvent injection may also occur in a vapour state and its objective is to reduce oil viscosity and improve mobility of bitumen under low temperatures Ͻ100°C. In general, hydrocarbon solvents such as propane are often used for this application. The objective of this study is to conduct CT-based measurement of static mixing of bitumen and both liquid and vapour phase solvents, and to quantify some of the time-dependent changes that occur during solvent mixing with bitumen.Diffusion experiments have been conducted with propane and DME (vapour phase) and with propane, DME, pentane and toluene (liquid phase) solvent systems. Solvents are mixed with medium viscosity Peace River bitumen and high viscosity Grosmont bitumen. The Tests are run under constant pressure and temperature, and Computer-Assisted Tomography (CT) is used to monitor mass transfer of solvent into oil as a function of time. The outcome of this study is measurements of mass transfer rates of solvent into oil, and the degree of oil phase swelling during the tests.During solvent injection processes in the field, the rate of mixing is a key parameter that will help in deciding which solvent is optimal for different processes. This study focuses on the rate of solvent mixing with oil. In vapour phase solvent systems, the analysis of the CT images allows for an understanding of the impact of oil phase swelling on the effective rate of penetration of solvent into oil. Overall, the test data provided in this work demonstrates that DME mixes into oil faster than other solvents, and leads to more swelling in a vapour solvent-bitumen system. The analysis of CT data provides an understanding of concentration-dependent diffusion coefficients and limitations from predicting mass transfer using constant coefficients in liquid and vapour solvent systems.