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 methodslow-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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