Advances in Oil and Water Saturation Measurements Using Low Field NMR
Bryan, J., Mai, A., Hum., F.M. and Kantzas, A.
SPE/PS-CIM/CHOA 97802, presented at the 2005 SPE International Thermal Operations and Heavy Oil Symposium held in Calgary, Alberta, Canada, 1-3 November 2005;
SPEREE, 9(6), 654-663, 2006.
Low field nuclear magnetic resonance (NMR) relaxometry has been successfully used in the past to perform in-situ estimates of oil and water content in unconsolidated oil sand samples.This work has intriguiging applications in the oil sands mining and processing industry, in the areas of ore and froth characterization.Studies have previously been performed on a database of ore and froth samples from the Athabasca region in northern Alberta, and preliminary results have been encouraging.In this paper, supporting data is presented and refinements suggested to the previous algorithms, to improve the oil and water saturation predictions.
A suite of real and synthetic samples of bitumen, water, clay and sand have been used to investigate the physical interactions of the different components on the NMR spectra.An automated algorithm is used to separate the oil and water NMR signals, and this algorithm is tested against samples both from this zone and from other heavy oil fields.Moreover, 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 both in-situ 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 oil industry in this country 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 using surface mining technology1.In 2003, this translated to 35% of all heavy oil and bitumen production1, and billions of dollars have been invested by numerous companies 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 formations2.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 saturation with depth and location in the reservoir. In-situ fluid content determination using 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 of material in the separator tanks will allow for improved process optimization and control.The industry standard for accurately measuring oil, water and solids content is Dean-Stark (DS) extraction3.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 by mass balance.The problem with DS is that it is expensive and time consuming.Centrifuge technology is often used for faster process control, but this is highly inaccurate due to similar fluid densities and the presence of emulsions.New methods for fast measurements of oil, water and solids content are needed.