The role of macropores in soil and water processes has motivated many researchers to describe their sizes and shapes. Several approaches have been developed to characterize macroporosity, such as the use of tension infiltrometers, breakthrough curve techniques, image‐analysis of sections of soils, and CAT scanning. Until now, efforts to describe macropores in quantitative terms have been concentrated on their two‐dimensional (2‐D) geometry. The objective of this study is to nondestructively quantify the three‐dimensional (3‐D) properties of soil macropores in four large undisturbed soil columns. The geometry and topology of macropore networks were determined using CAT scanning and 3‐D reconstruction techniques. Our results suggest that the numerical density of macropores varies between 13421 to 23562 networks/m3 of sandy loam soil. The majority of the macropore networks had a length of 40 mm, a volume of 60 mm3, and a wall area of 175 mm2 It was found that the greater the length of networks, the greater the hydraulic radius. The inclination of the networks ranged from vertical to an angle of ≈55° from vertical. Results for tortuosity indicated that most macropore networks had a 3‐D tortuous length 15% greater than the distance between their extremities. More than 60% of the networks were made up of four branches. For Column 1, it was found that 82% of the networks had zero connectivity. This implies that more than 4/5 of the macropore networks were composed of only one independent path between any two points within the pore space.

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 work involves the detection and monitoring of solvent interactions with heavy oil and bitumen. Two nondestructive methodslow-field nuclear magnetic resonance (NMR) and X-ray computer-assisted tomography (CAT)were used. It is shown that low-field NMR can be a very useful tool in understanding the relationship of viscosity, density, and asphaltene precipitation in bitumen−solvent mixtures. Such mixtures are present in solvent-related heavy oil and bitumen recovery processes, such as vapor extraction (VAPEX). As a solvent comes into contact with a heavy oil or bitumen sample, the mobility of hydrogen-bearing molecules of both solvent and oil changes. These changes are detectable through changes in the NMR relaxation characteristics of both the solvent and the oil and can be correlated to mass flux and concentration changes. Based on Fick's second law, diffusion coefficients were calculated for combinations of three oils and six solvents. X-ray CAT scanning was also used in parallel for analysis of solvent diffusion into the bitumen. As the solvent was diffusing into the bitumen, a concentration gradient was obtained. Concentration values at certain times were used to calculate diffusion coefficients, which were compared with results obtained from NMR data, using both an analytical method and a numerical method. The diffusion coefficients were considered either as constants or as functions of solvent concentration in two models that have been developed during this research. The overall diffusion coefficients calculated for several pairs of oils and solvents at different ratios, both by NMR data and X-ray tomography, were on the order of 10-6 cm2/s.

The kinetics of water uptake and redistribution in several soils and their components are studied using NMR relaxometry. Unlike the normal behavior observed in stable porous media, entry into micropores in the soil is a slow process as compared to entry into macro- and mesopores. This indicates that soils air-dried at ambient temperature include gel phases that have collapsed or reoriented, closing micropores, during drying. Wetting must then include the swelling processes that re-open micropores. This can even exhibit temperature dependence giving an "apparent activation energy" comparable to that of a chemical reaction, for example, ester hydrolysis. The processes of micropore opening may play a role in slow uptake of contaminants into soils.

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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.