Knowledge of oil viscosity is important when estimating hydrocarbon reserves and evaluating the potential for waterflooding or EOR processes. This information is especially important in heavy oil and bitumen, as viscosity is usually the major impediment to recovery of these reserves. As oil viscosity increases, obtaining a laboratory measurement is difficult and prone to error, and viscosities measured in the lab may not be representative of field conditions. Nuclear magnetic resonance (NMR) is therefore presented as an attractive alternative method for determining oil viscosity. Several correlations already exist for determining oil viscosity using NMR. Some of these correlations compare the geometric mean T2 relaxation time to oil viscosity, while others relate viscosity to the apparent hydrogen index. This paper examines these different models on a suite of conventional and heavy oil samples. It is concluded that none of the existing models can accurately predict oil viscosity for both conventional and heavy oils, especially for oils with viscosity higher than 20,000 cP. All the measured oil samples show a correlation between oil viscosity and the geometric mean T2 relaxation time, and also between viscosity and relative hydrogen index. This is consistent with what other experimenters have noticed. An empirical model is developed, correlating oil viscosity to both of these parameters. Unlike previous models, this model can accurately predict oil viscosity for both conventional and heavy oil. The wider range of this model makes it useful for laboratory analysis of oil viscosity using NMR. If the results of this model can be applied to in situ oils, NMR can be used as a logging tool to characterize heavy oil and bitumen formations. The model presented in this paper is the first step towards successfully predicting viscosity in situ. Introduction Determination of oil viscosity is extremely important to the development of any potential oil reservoir. If waterflooding is being considered as a recovery scheme, the mobility ratio between oil and water will have a strong effect on the macroscopic sweep efficiency of the waterflood. Likewise, when considering possible EOR schemes, oil viscosity is one of the most serious impediments to the success of these schemes. Oil viscosity is also a required input parameter for reservoir simulation and well testing. In heavy oil and bitumen reservoirs, the high oil viscosity is often the limiting factor to efficient oil recovery. Waterflooding cannot be used in these reservoirs, due to the adverse mobility ratio between oil and water. The oil is so much more viscous than water that injected water will move through the oil in the form of "viscous fingers," which lead to early water breakthrough and poor sweep efficiency. If attempting a miscible solvent or gas flood, knowledge of oil viscosity is necessary for estimating the efficiency of the flood. Due to the negative effects of the adverse mobility ratio, viscosity reduction is the main focus of EOR schemes in heavy oil reservoirs.

Summary The nuclear magnetic resonance (NMR) signal obtained from conventional oil, heavy oil, and bitumen formations can consist of both hydrocarbon and watersignals. Each NMR signal can further characterize both mobile and immobile fluids in the porous media. However, as the viscosity of the hydrocarbon phase increases and the NMR signal shifts toward lower relaxation times, the composite NMR signal for the hydrocarbon-bearing formation becomes very complicated. As the viscosity of the bitumen exceeds 100,000 cp (at natural conditions), the relaxation characteristics of bitumen become partially nondetectable by both the logging and laboratory NMR tools. As a result, the conventional methods of NMR detection fail to precisely recognize the hydrocarbon components. Laboratory NMR measurements of bitumen-bearing porous media under different temperatures were performed. This method delivered new information about bitumen reserves in situ. The results show that low-field NMR holds promise for the characterization of recoverable heavy oil and bitumen reserves. This new approach can be applicable for real-time monitoring of thermal extraction, including monitoring the efficiency of thermal recovery methods. Introduction NMR logging tools are currently used for determining reservoir properties such as porosity1,2 and permeability,1–4 as well as the presence of mobile and immobile fluids.5-8 Recent developments in NMR research offer tools for separating water, oil, and gas from the combined NMR signal.9–11 Very little is known about the use of NMR logging tools for the in-situ characterization of crude oils.1 With respect to heavy-oil and bitumen formations, NMR logging has not been very successful in characterizing crude oil (viscosity>100,000 cp). The reason for this is the fact that the spectra from most heavy-oil and bitumen formations cannot be adequately detected by the NMR logging tools. This is because the shortest relaxation times (t2's) of the spectra at normal temperature conditions (T 30°C) are lost. High-field NMR technology has solved such problems in the past but is not currently available to be used downhole.12,13 A fundamental objective of the research performed in our laboratory was to extend the use of NMR logging tools to heavy-oil and bitumen formations, particularly during thermal recovery projects. To this end, the NMR characteristics of these types of hydrocarbons in bulk volume and in porousmedia were investigated.8,14 The objective of this work was to investigate the NMR characteristics of these bitumens and heavy oils at elevated vs. ambient temperatures and to isolate the oil signal from the combined NMR spectrum of the formation. The hydrocarbon and water saturations were then determined. The possibility of increasing the quality of NMR data by increasing the signal-to-noise ratio and by proper reconstruction of the wholet2 spectra was also investigated. These objectives were achieved by performing a series of experiments, which addressed the following issues:Variable-temperature NMR spectra determination for bitumen-saturated cores to estimate different fluid components in porous media in situ.NMR characterization of brines, conventional oils, heavy oils, and bitumen in bulk volume at different temperatures.Estimation of the parameters of NMR tools and their applicability for monitoring thermal recovery processes. It must be noted that La Torraca et al.15 provided laboratory data that correlate NMR properties to viscosity of heavy oils ranging from <1,000 cp to >100,000 cp. Then they combined NMR log and conventional log data to predict the in-situ oil viscosity in two heavy-oil reservoirs. This work,15 although similar in nature to the work presented here, deals with oil reservoirs having 3 to 4 orders of magnitude less viscosity. Unfortunately, algorithms presented in the literature seem to collapse when applied to bitumen formations. Experimental Phase All field measurements for bitumen sands characterization were performed with a Schlumberger CMR-200™ logging tool. All measurements were done at natural in-situ conditions; the maximum recorded temperature was T=14°C.One example of these results is presented in Fig. 1. The entire NMR laboratory testing was performed with a custom-built Numar Corespec 1000™. This is a unique system with a separate temperature control for heating the magnet and the sample. The equipment was installed and tuned at the TIPM Laboratory and operates at a frequency of 1 MHz. All the samples were tested at different temperatures and at ambient pressure with a standard methodology developed for NMR log calibration. 16 All decay data were translated into NMR spectra with algorithms developed in-house and the NUMAR standard analysis packages 6 that are included with the spectrometer. Several sets of experiments were performed to address each of the issues mentioned earlier. Variable-Temperature NMR Spectra of Core. Variable-temperature NMR was used to determine the fluid components in bitumen- and water-saturated cores. The first set of experiments involved the testing of native state cores at different thermal conditions. Native-state bitumen-saturated plug samples were cut from full-size core using a liquid-nitrogen-cooled cutter. Testing started with NMR measurements at the following temperatures: 1°C, 6°C, 8°C, 12°C, 16°C, 22°C, 25°C, 30°C, 40°C,45°C, 50°C, 60°C, 65°C, 70°C, 75°C, and 80°C. For all measurements, a CPMG sequence was applied with interecho times of 0.3 and 0.6 ms. The NMR spectra were recovered. After completion of the temperature-cycle testing, the native-state bitumen-saturated plugs were saturated under vacuum with an aqueous paramagnetic solution (2N CuSO4, T2 1ms). The fact that water entered the cores under vacuum implies that some drying occurred during core handling. This procedure was performed to eliminate the water signal from subsequent NMR testing. The samples were measured at 30°C. Following the NMR data collection with the paramagnetic solution, the sand samples were cleaned using the Dean-Stark method (thus removing all bitumen) and resaturated with 2%NaCl brine. The brine-saturated samples were tested in the NMR again at the previous temperatures. This determined that the NMR spectrum of the sample was free of any bitumen effects, measuring only structural and mineralogical effects. X-ray diffraction (XRD) analyses were performed to determine clay type and concentration. In accordance with these analyses, a set of artificial samples(sand + clay) was constructed. All samples were saturated with 2% NaCl brine. The brine-saturated artificial samples were tested to determine the NMR spectra, again at the temperatures mentioned above. Examples of the obtained spectra set are presented in Figs. 2 through 4.

During production operations in heavy oil and bitumen formations where thermal recovery methods are applied, the fluids produced are often in the form of emulsions. This is also true in non-thermal recovery methods whenever oil and water are coproduced, but to a lower degree of severity. Conventional flow measuring devices are capable of measuring oil and water streams when they are segregated, but they fail when oil-in-water or water-in-oil emulsions form. Conventional methods are also not reliable when there are solids flowing in the stream. Low field NMR relaxometry was successfully tested as a tool for accurately measuring the oil and water content of such streams with and without emulsions present in the samples. The method was proved to be at least as good as conventional extraction methods (i.e., Dean-Stark). The technology was tested with both artificially and naturally occurring emulsified streams with accuracy better than 96﹪. This extremely encouraging result led to the design of an online NMR relaxometer for oil/water stream measurements under the conditions encountered in the production of heavy oil and bitumen. Introduction In the recovery of bitumen, viscosity reduction becomes important, both below and above the ground. The addition of a liquid diluent is thought to break down or weaken the intermolecular forces which create high viscosity in bitumen(1). The effect is so dramatic that the addition of even 5﹪ diluent can cause a viscosity reduction in excess of 80%; thus, facilitating the in situ recovery and pipe line transportation of bitumen. The knowledge of the bitumen-diluent viscosity is highly important, since without it, calculations in upgrading process, in situ recovery, well simulation, heat transfer, fluid flow, and a variety of other engineering problems would be difficult or impossible to solve. This paper presents the development of a simple correlation to predict the viscosity of binary mixtures of bitumen-diluent in any proportion. Experimental The data used for the development of the correlation was TABLE 1: Bitumen data at 30 °CDATA[C. Available In Full Paper. TABLE 2: Diluent data at 30 °CDATA[C. Available In Full Paper. obtained from Wallace et al.(2) and Wallace and Henry(3).The data consisted of a total of 99 points obtained from three bitumens and five diluents, respectively, listed in Tables 1 and 2. Each of these bitumen samples was diluted at 30 °CDATA[C to 5, 10, 25, 50 and 75 weight ﹪ diluent with each of the diluents. After mixing, the samples were reweighed, and any weight loss was attributed to solvent evaporation. The diluent weight fractions were adjusted accordingly, and the viscosities of the mixtures measured. For a detailed account of experimental procedures, refer to Wallace and Henry(3). Correlation Development Many correlations have been developed to predict the viscosity characteristics of bitumen-diluent mixtures(1-6). While several have been successful in making these predictions, most are cumbersome to use. Low Field Nuclear Magnetic Resonance (NMR) relaxometry techniques were developed in the laboratory to enhance and support comparable NMR logging tools that are currently used downhole.

A fast and accurate method for the group analysis of crude oils in porous media that describes petroleum components (especially heavy fractions) has been developed. NMR structure group analysis is used as the tool for the characterization of crude oils. This method is proposed as an alternative to existing complicated and laborious methods of characterization of extracted oil samples. Currently, group analysis of heavy fractions of crude oils is being investigated by means of chromatographic methods, such as the SARA (saturates-aromatics-resinsasphaltenes) test. These methods are usually expensive, and require considerable work from qualified personnel. Furthermore, these methods cannot be used for estimating the oil components in situ. The basis of determining crude oil components using NMR is the difference of the nuclei mobility in the different hydrocarbons during the NMR testing period. A combination of solvent extraction, NMR testing and data processing gives a series of NMR terms that are then used to specify hydrocarbon mixtures and their components both in the bulk phase and in unconsolidated porous media. Introduction NMR logging tools are currently used for determining reservoir properties such as porosity(1, 2), permeability(1-4), as well as mobile and immobile fluids(5-7). Recent developments in NMR research offer tools for separating water, oil, and gas from the combined NMR signal(7, 8). Very little is known about the use of NMR logging tools for the in situ characterization of crude oils(1). With respect to heavy oil and bitumen formations, NMR logging has not been very successful in characterizing crude oil. The reason for the lack of such success is the fact that the NMR logging tools cannot detect the spectra from most heavy oil and bitumen formations. It should be noted that high field NMR technology has solved such problems in the past, but such technology cannot be used downhole. A fundamental objective of the research performed in our laboratory is to extend the use of NMR logging tools to all heavy oil and bitumen formations. To this end, the NMR characteristics of heavy oils in porous media were investigated(9, 10). The objective of our work is to isolate the oil signal from the combined NMR spectrum of the formation, and then shift it towards the relaxation time range that can be detected by the conventional NMR logging tools. Once this goal is achieved, NMR logs of heavy oil and bitumen formations can become successful in the analysis of oil downhole. This objective was accomplished in the material presented in this paper through a series of experiments that addressed the following issues:Relaxation interactions in mixtures of simple organic liquids with water.Relaxation interactions in mixtures of simple organic liquids. Relaxation interactions in mixtures of simple organic liquids with solvents.Relaxation times of conventional crude oils with and without solvents present.Relaxation times of heavy crude oils and bitumen with and without solvents present.Relaxation times of heavy crude oils and bitumen with and without solvents in unconsolidated sands and with variable connate water saturation.

Two key problems in studying the interaction of organic contaminants with soils in environmental remediation are (1) the monitoring of the contaminant evolution in the soil matrix and (2) the understanding of soil/fluid interactions. To study these two problems we have developed a combination of routine analysis (density and grain size analysis techniques) and novel instrumental monitoring techniques. These monitoring techniques are X--ray computer assisted tomography (CAT) scanning, nuclear magnetic resonance (NMR), and X-ray diffraction (XRD). This paper shows how these methods can be combined to study contaminant interaction with soil, as well as the identification of different states of an aqueous phase in the soil pore space. From this combination of techniques, we have been able to monitor qualitative changes in the soil matrix induced by the presence of an aqueous phase and a contaminant phase. Our results indicate that the contaminant (that happened to be a pesticide in these tests) interacts with the soil matrix and reduces the ability of water to interact with the soil. Introduction Environmental-contaminant and soil interaction phenomena are of great importance in remediation problems, and have received a large amount of attention in the literature(1). The understanding of these interactions will allow for a better modelling of contaminant transport, biodegradability, and toxicity. To study the interactions of a contaminant with a given soil, one must first have a full understanding of the soil properties (stationary phase). The reason for this is that soils are of a complex heterogeneous nature(2). In this study we have used the Armadale soil (also known as Mossy Point soil), which has been extensively studied at the University of Calgary(1, 3, 12). This soil has been analysed in its native state both chemically and physically. The chemical analysis consisted of conventional wet chemistry and XRD for mineral determination. The physical analysis consisted of density and grain size distribution measurements. The next step was to study the water/soil interaction with water being considered as a single mobile phase. To do this type of analysis, the preferred technology must be nondestructive and must have the ability to perform time-controlled measurements. There are two techniques that are well suited for this work and have the above properties (1) NMR imaging (MRI) and/or NMR relaxometry, and (2) CAT scanning. The imaging via MRI of water in soils has been shown to be feasible if the soil is low in iron (especially ferromagnetic iron) and other paramagnetic species(4, 5). These same conditions hold for any type of NMR study on soils. X-ray CAT scanning has been shown to be a very powerful tool in soil characterization(2, 17, 18). In parallel to NMR and CAT scanning testing, capillary pressure measurements were also made. The final step was to measure contaminant properties in soil in the presence of water. In this paper, a high-concentration pesticide solution was used as the contaminant. The developed methodology is presented through a series of preliminary tests.