J. Bryan

Potential for Alkali-Surfactant Flooding in Heavy Oil Reservoirs Through Oil-in-Water Emulsification

Alkali-surfactant flooding is an established enhanced oil recovery technique in conventional oil reservoirs, whereby the injected chemical lowers the oil/water interfacial tension, leading to reduced trapping of oil ganglia. In the past, there have been some studies of alkali and alkali-surfactant flooding of heavy oil systems as well, and it has been observed that chemical injection can lead to improved oil recovery. The heavy oil recovery mechanism proposed in this work is the creation of oil-in-water emulsions, which may form under conditions of low interfacial tension and shear due to flow through rock pores. Oil may either be produced in the water (emulsification and entrainment) or the droplets may coalesce or plug the rock pores, leading to improved sweep efficiency (emulsification and entrapment). Both of these mechanisms are investigated in laboratory systems of varying rock permeability, using a heavy oil with a viscosity of 11,500 mPa·s. When oil-in-water emulsions form, the oil recovery can be improved significantly, even without the addition of polymer for mobility control. The effect of permeability and varying injection rates are considered, to understand how different ranges of shear affect the efficiency of these emulsion systems.

Viscosity Determination of Heavy Oil and Bitumen Using NMR Relaxometry

Knowledge of oil viscosity is important when estimating hydrocarbon reserves and evaluating the potential for water-flooding of 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 measured in the lab may not be 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 T 2 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 sample show a correlation between oil viscosity and the geometric mean T 2 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 succesfully predicting viscosity in situ.

In Situ Viscosity of Heavy Oil: Core and Log Calibrations

Having knowledge of oil viscosity variation within reservoirs would be of considerable benefit when producing from heavy oil fields. Previous work has demonstrated that low field NMR bench-top instruments can be used to perform measurements of in situ viscosity. Ideally, if these measurements could be performed on NMR logging tools, viscosity characterization studies could be carried out using fewer core samples. In this paper, data is presented for a heavy oil reservoir in northern Alberta. A methodology is presented for tuning NMR viscosity estimates to the field in question, and core analysis results are collected, showing that in situ viscosity predictions are possible in the laboratory. NMR spectra measured in the laboratory are compared to NMR logging tool spectra, in order to determine if results obtained using bench-top instruments can be extrapolated to logging tool data.

Measurement of emulsion flow in porous media: Improvements in heavy oil recovery

Many heavy oil and bitumen reservoirs in the world are too small or thin for thermal enhanced oil recovery methods to be economic. In these fields, novel methods of less energy intensive, non-thermal technologies are required. Previous experience has shown that the injection of low concentrations of aqueous alkali-surfactant solutions into the reservoir can significantly improve the oil recovery, beyond that of waterflooding. This is due to the in-situ formation of emulsions, which plug off the water channels and lead to improved sweep efficiency in the reservoir. The proper control of these floods requires methods for monitoring the formation and effect of these emulsions. In this paper, the results of laboratory core floods are interpreted to demonstrate how the pressure and flow response can be related to the formation of these emulsions. A new technique (low field NMR) is also used to directly measure W/O emulsions in porous media. Finally, a numerical study is performed in order to demonstrate how the in-situ formation of emulsions can be simply represented in simulation software.

Determining Bitumen, Water and Solids in Oil Sands Ore by Using Low-Field NMR

In previous work, low-field nuclear magnetic resonance (NMR) has been considered as a fast and non-destructive method to characterize oil and water. In this work, we continue to use the low-field NMR technique to determine the amount of bitumen, water and solids for unconsolidated oil sand ores from two different depositional environments. Simple T 2 cutoff and signal deconvolution are applied to the NMR spectra to estimate bitumen and water content. Comparison results are given. It has been found previously that, in most cases, the signals from clay-bound water and bitumen overlap; thus, the estimation of fluid content needs correction. To replace the well-known Dean-Stark extraction method, it is necessary to seek a fast, simple, non-destructive and inexpensive method. A densitometry technique, with simultaneous pore volume measurement, is developed to provide the volume of the ore sample and complement the NMR results. A density algorithm is introduced to determine fluid and solid content. Results from pore-volume measurements are comparable with those from Dean-Stark extraction and low-field NMR. A combined NMR-pore volume technique appears to minimize errors compared to Dean-Stark extraction.

Evaluation of Bitumen-Solvent Properties Using Low Field NMR

The VAPEX (vapour extraction) process is a new technique for the recovery of highly viscous heavy oil and bitumen. This process involves injection of vapourized hydrocarbon solvent into heavy oil and bitumen reservoirs and production of the resulting solvent-diluted oil that drains by gravity in a horizontal well. Research has shown that this process is highly efficient and that different solvents give different results. In this paper, six different solvents were added to several oils of different viscosities and densities. The solvents were added in different ratios to each of the oils and NMR spectra were obtained. The mixture of solvent and heavy oil or bitumen produces a spectrum that is distinctly different than that of the solvent or oil alone. From the shape and amplitude of the NMR spectra, one can calculate the amount of solvent present. Furthermore, one can predict the viscosity of the mixture without any additional viscosity measurements. As asphaltenes precipitate with the addition of solvent(s), one can correlate the amount of asphaltene reduction to changes in the NMR spectra. In this manner, NMR can possibly be used to show the asphaltene precipitation of different oils in the presence of solvent(s). By measuring the amount of asphaltene precipitation, NMR can also provide an indication of in situ upgrading of the oil that occurs with the addition of solvent(s). Using NMR as an analysis tool, the effect of the different solvents on viscosity reduction and asphaltene precipitation is quantified.

Study of the settling characteristics of tailings using nuclear magnetic resonance technique

The oil sands mining and extraction processes in Canada produce large volumes of tailings that are a mixture of mainly water, clay, sand, chemicals and bitumen. This residue is deposited into tailings ponds where sand settles faster than fine clays which require many years to fully consolidate. Therefore, land reclamation and water recirculation become significant environmental issues. The tailings settling rate depends on particle size, density and surface properties which can be modified by variations in the pH, salinity, and addition of flocculants and/or coagulants. Although plant scale developments have been made to improve tailings settling rates, there is a need for an on-site fast measurement of tailings settling characteristics to determine process modifications. This study uses the nuclear magnetic resonance (NMR) technique to analyse variations in tailings settling properties. The results show the NMR technique has potential as an online application to estimate the lifetime of a pond and to monitor oil sands processing.

Evaluation of bitumen-solvent properties using low field NMR

The VAPEX (vapour extraction) process is a new technique for the recovery of highly viscous heavy oil and bitumen. This process involves injection of vapourized hydrocarbon solvent into heavy oil and bitumen reservoirs and production of the resulting solvent-diluted oil that drains by gravity in a horizontal well. Research has shown that this process is highly efficient and that different solvents give different results. In this paper, six different solvents were added to several oils of different viscosities and densities. The solvents were added in different ratios to each of the oils and NMR spectra were obtained. The mixture of solvent and heavy oil or bitumen produces a spectrum that is distinctly different than that of the solvent or oil alone. From the shape and amplitude of the NMR spectra, one can calculate the amount of solvent present. Furthermore, one can predict the viscosity of the mixture without any additional viscosity measurements. As asphaltenes precipitate with the addition of solvent(s), one can correlate the amount of asphaltene reduction to changes in the NMR spectra. In this manner, NMR can possibly be used to show the asphaltene precipitation of different oils in the presence of solvent(s). By measuring the amount of asphaltene precipitation, NMR can also provide an indication of in situ upgrading of the oil that occurs with the addition of solvent(s). Using NMR as an analysis tool, the effect of the different solvents on viscosity reduction and asphaltene precipitation is quantified.

Comparative Investigation of Thermal Processes for Marginal Bitumen Resources

With the depletion of conventional oil resources, heavy oil and bitumen play an increasingly important role as the main resources for crude oil. This is particularly true in Alberta since it has in excess of 400 x 109m3 of heavy oil and bitumen. In Canada, most of heavy oil and bitumen resources are developed with thermal methods.