Oil and Water Content Measurements in Bitumen Ore and Froth Samples Using Low Field NMR
- Jonathan L. Bryan (U. of Calgary) | An T. Mai (U. of Calgary) | Florence M. Hum (U. of Calgary) | Apostolos Kantzas (U. of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- December 2006
- Document Type
- Journal Paper
- 654 - 663
- 2006. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 4.1.5 Processing Equipment, 1.2.3 Rock properties, 5.1 Reservoir Characterisation, 5.6.1 Open hole/cased hole log analysis, 5.6.2 Core Analysis, 5.2 Reservoir Fluid Dynamics, 4.3.4 Scale, 5.3.1 Flow in Porous Media, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.5.2 Core Analysis, 2.4.3 Sand/Solids Control, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.2 Separation and Treating
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Low-field nuclear magnetic resonance (NMR) relaxometry has been used successfully to perform estimates of oil and water content in unconsolidated oil-sand samples. This work has intriguing applications in the oil-sands mining and processing industry, in the areas of ore and froth characterization. Studies have been performed on a database of ore and froth samples from the Athabasca region in northern Alberta, Canada. In this paper, new automated algorithms are presented that predict the oil- and water-weight content of oil-sand ores and froths.
Suites of real and synthetic samples of bitumen, water, clay, and sand have also been used to investigate the physical interactions of the different parameters on the NMR spectra. Preliminary observations regarding spectral properties indicate that it may be possible in the future to estimate the amount of clay in the samples, based upon shifts in the NMR spectra. NMR estimates of oil and water content are fairly accurate, thus enhancing the possibility of using NMR for oil-sands development and in the oil-sands mining industry.
The oil sands of northern Alberta contain some of the world's largest deposits of heavy oil and bitumen. As our conventional oil reserves continue to decline, these oil sands will be the future of the Canadian oil industry for years to come and will allow Canada to continue to be a world leader in both oil production and technology development. Approximately 19% of these bitumen reserves are found in unconsolidated deposits that lie close enough to the surface that they can be recovered with surface-mining technology (Alberta Energy and Utilities Board 2004). In 2003, this translated to 35% of all heavy-oil and bitumen production (Alberta Energy and Utilities Board 2004), and numerous companies have invested billions of dollars in oil-sands mine-development projects. Furthermore, many in-situ bitumen-recovery options are currently being designed and field tested for recovering oil in deeper formations (Natl. Energy Board 2004). Being able to predict oil properties and fluid saturation in situ and process optimization of bitumen extraction (frothing) is therefore of considerable value to the industry.
There are several areas in oil-sands development operations where it is important to have an estimate of the oil, water, and solids content of a given sample. During initial characterization of the reservoir, it is necessary to determine oil and water content with depth and location in the reservoir. Fluid-content determination with logging tools would be beneficial for all reservoir-characterization studies, whether for oil-sands mining or in-situ bitumen recovery. In mining operations, during the processing of the mined oil-sand ore, having information about the oil, water, and solids content during the extraction process will allow for improved process optimization and control. The industry standard for measuring oil, water, and solids content accurately is the Dean-Stark (DS) extraction method (Core Laboratories 1992). This is essentially a distillation procedure, whereby boiling solvent is used to vaporize water and separate the oil from the sand. Oil, water, and solids are separated and their contents measured separately. The problem with DS is that it requires large amounts of solvents and is time consuming. Centrifuge technology is often used for faster process control, but this can be inaccurate because of similar fluid densities and the presence of emulsions. New methods for fast measurements of oil, water, and solids content are needed.
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