Oil and Water Content Measurements in Bitumen Ore and Froth Samples Using Low Field NMR

2006 ◽  
Vol 9 (06) ◽  
pp. 654-663 ◽  
Author(s):  
Jonathan L. Bryan ◽  
An T. Mai ◽  
Florence M. Hum ◽  
Apostolos Kantzas
Keyword(s):  
Water Content ◽  
Oil Sands ◽  
Oil Sand ◽  
Low Field ◽  
Oil Sands Mining ◽  
Characterization Studies ◽  
Oil Water ◽  
Solids Content ◽  
Northern Alberta

Summary 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. Introduction 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.

A rapid method for the determination of bitumen, water, and solids in oil sands

1981 ◽  
Vol 59 (10) ◽  
pp. 1527-1530 ◽  
Author(s):  
D. Lorne Ball ◽  
E. D. Cooke ◽  
Jean M. Cooley ◽  
M. Coreen Hamilton ◽  
Robert Schutte
Keyword(s):  
Rapid Method ◽  
Oil Sands ◽  
Isopropyl Alcohol ◽  
Water Concentration ◽  
Mass Balances ◽  
Oil Sand ◽  
Karl Fischer Titration ◽  
Plant Operations ◽  
Solids Content

A simple and rapid method has been developed to measure the bitumen, water, and solids content of Athabasca oil sand samples in order to efficiently serve both plant operations and research needs. A solvent blend of 74% toluene and 26% isopropyl alcohol extracts both the bitumen and the water from the solids producing a homogeneous liquid phase. The bitumen is determined gravimetrically on an aliquot of this solution. A Karl Fischer titration is used to measure the water concentration. Solids are measured gravimetrically or can be reported by difference. Mass balances between 99.05 and 100.25% are achieved routinely.

Electrical properties of Athabasca Oil Sands

1979 ◽  
Vol 16 (10) ◽  
pp. 2009-2021 ◽  
Author(s):  
F. S. Chute ◽  
F. E. Vermeulen ◽  
M. R. Cervenan ◽  
F. J. McVea
Keyword(s):  
Electrical Properties ◽  
Moisture Content ◽  
Oil Sands ◽  
Relative Dielectric Constant ◽  
Dielectric Constants ◽  
Graphical Form ◽  
Oil Sand ◽  
Wide Range ◽  
Realistic Assessment

The results of a series of laboratory measurements of the electrical properties of samples of oil sand from the Athabasca deposit in northeastern Alberta are reported. The electrical conductivity and relative dielectric constant of the samples have been determined over a frequency range extending from 50–109 Hz. The measurements were performed on samples with a wide range of moisture content and over a temperature range from about 3–150 °C. A discussion of the methods and apparatus used is included.Sufficient data have been collected to permit correlation of the electrical properties of oil sand with density, moisture content, and temperature, and hence to indicate how the laboratory results can be extended to estimate in situ conductivities and dielectric constants. The results of these correlations, which are presented in graphical form, are of fundamental importance in any realistic assessment of the viability of electromagnetically heating large in situ deposits of oil sand.

scholarly journals Tar on Tap

2008 ◽  
Vol 130 (12) ◽  
pp. 30-34
Author(s):  
Bridget Mintz Testa
Keyword(s):  
Oil Sands ◽  
Surface Mining ◽  
Recycled Water ◽  
Petroleum Production ◽  
Production Processes ◽  
Production Wells ◽  
Oil Demand ◽  
Northern Alberta ◽  
In Situ Production

This article explores diverse ways adopted by companies to find ways to make extracting oil from the sands of northern Alberta a little easier. At Petrobank’s Whitesands site, heat from in situ combustion both melts and upgrades the bitumen in the underground deposit. Horizontal production wells carry the oil to the surface. However, even with the new processes in place, copious quantities of energy and water are needed to produce oil from sands. In situ production processes exploit bitumen deposits that are inaccessible through surface mining. The facility at EnCana’s Foster Creek site processes some of the water used to extract bitumen in situ. That recycled water is then boiled and reinjected below the surface. Environmental arguments aside, many observers contend that the only argument against exploiting the Alberta oil sands that might have any success is economic—that it might cost more than alternatives. The paper concludes that barring some unforeseen calamity, oil demand is expected to outstrip the capacity of conventional petroleum production. Even if wringing oil from the Alberta sands is expensive and energy-intensive, it is probably a cost most consumers will be willing to pay for access to the next easiest oil.

The Introduction of the Microchanneling Phenomenon to Cyclic Steam Stimulation and Its Application to the Numerical Simulator (Sand Deformation Concept)

1984 ◽  
Vol 24 (04) ◽  
pp. 417-430 ◽  
Author(s):  
Yoshiaki Ito
Keyword(s):  
Oil Sands ◽  
Steam Injection ◽  
Physical Interaction ◽  
Oil Sand ◽  
Horizontal Fracture ◽  
Micro Channels ◽  
Flow Geometry ◽  
Production Temperature ◽  
Fluid Production

Ito, Yoshiaki, SPE, Gulf Canada Resources Inc. Abstract Historically, a vertical or horizontal fracture is believed to be a main recovery mechanism for a cyclic steam-injection process in unconsolidated oil sands. Most current computer process in unconsolidated oil sands. Most current computer models for the process are based on the fracture concept. With the postulated sand deformation concept, on the other hand, the injected fluid is able to penetrate the unconsolidated oil sand by creating micro channels. When the pore pressure is reduced during production, these secondary flow channels will collapse totally or partially. Condensed steam tends to sweep fluids where the bitumen had been heated and imparts mobility as a result of the injected hot fluid. Flow geometry of the new concept is described in this paper. The physical differences between the sand paper. The physical differences between the sand deformation zone and the no-deformation zone are also investigated. The three major differences between these two zones are porosity change, pressure level, and energy and flow characteristics resulting from the existence of micro channels. All these modifications were incorporated successfully into a conventional numerical thermal simulator. The new model provided an excellent match for all the field observations (steam-injection pressure, oil-and-water production rates, fluid production temperature, downhole production rates, fluid production temperature, downhole production pressure, and salinity changes) of a production pressure, and salinity changes) of a steam-stimulated well in an unconsolidated oil sand. The study indicates that the most important phenomenon for in-situ recovery of bitumen is the one-way-valve effect of the micro channels, which are opened during injection and closed during production. Introduction A physical interaction between the injected fluid and the reservoir formation is required to inject large volumes of steam into the oil sand formation. Until now, this physical interaction was believed to be a vertical or a physical interaction was believed to be a vertical or a horizontal fracture, depending on the strength of the directional stress. Many authors investigated and incorporated this concept into numerical thermal simulators and used it for history match and prediction studies. There are many difficulties in analyzing the actual performance of steam stimulated wells by means of the performance of steam stimulated wells by means of the fracture concept. Some of the evidence is extremely difficult or impossible to explain with the conventional fracture concept. A few of these problems are discussed later. I, therefore, have postulated a new flow geometry to achieve a realistic interpretation of well performances. The new flow geometry has been termed the "sand deformation concept." The well performance characteristics for the bitumen recovery process can be described more clearly with the new concept process can be described more clearly with the new concept than with the conventional fracture concept. Sand Deformation Concept Although unconsolidated oil sand might not behave like a consolidated rock under stress, fracturing is assumed to be an important mechanism in most mathematical models for in-situ recovery of bitumen by steam injection. Fig. 1 A shows this process when the horizontal fracture is assumed to be the main recovery mechanism. Injected steam and condensate are contained primarily in a thin fracture zone so the fluid accommodated in the fracture will leak off. The process is similar to a linear displacement of oil by hot fluid. With the sand deformation concept, on the other hand, the injected fluid is able to penetrate oil sand through the creation of micro channels. Fig. 1 B shows this process. Since the micro channeling is postulated in the new model, a significant amount of resident fluid, including oil and connate water, will remain around the well without contacting the injected fluid. The extra space required to create the channels may be obtained by overburden heaving. Therefore, overburden movement will control the directional orientation of the channel creation. The preferential directional orientation is likely to be created as a result of preferential overburden movement. preferential overburden movement. Fig. 2 shows the rough dimensions of the pressurized channeling envelope surrounding the well when approximately 10 000 m3 [353,147 cu ft] of cold water equivalent as steam was injected. The shape of the areal extension is determined from the strength of the overburden stresses. SPEJ p. 417

scholarly journals Hyperspectral Characteristics of Oil Sand, Part 2: Prediction of Froth Characteristics from Measurements of Froth

Minerals ◽  
2020 ◽  
Vol 10 (12) ◽  
pp. 1137
Author(s):  
Benoit Rivard ◽  
Jilu Feng ◽  
Derek Russell ◽  
Vivek Bushan ◽  
Michael Lipsett
Keyword(s):  
Oil Sands ◽  
Imaging System ◽  
Surface Mining ◽  
Hyperspectral Data ◽  
Separation Performance ◽  
Oil Sand ◽  
Operating Environments ◽  
Solids Content ◽  
The Cost ◽  
High Solids Content

This is the second part of a study of predictive models of oil sand ore and froth characteristics using infrared hyperspectral data as a potential new means for process control. In Alberta, Canada, bitumen in shallow oil sands deposits is accessed by surface mining and then extracted from ore using flotation processes. The ore displays variability in the clay, bitumen, and fines content and this variability affects the separability and product quality in flotation units. Flotation experiments were performed on a set of ore samples of different types to generate froth and determine the ore processability (e.g., separation performance) and froth characteristics (bitumen and solids content, fines distribution). We show that point spectra and spectral imagery of good quality can be acquired rapidly (<1 s and <15 s, respectively) and these capture spectral features diagnostic of bitumen and solids. Ensuing models can predict the solids/bitumen (r2 = 0.88) and the %fines and ultrafines (particle passing at 3.9 and 0.5 µm) content of froth (r2 = 0.8 and 0.9, respectively). The latter model could be used to reject froth with a high solids content. Alternately, the strength of the illite-smectite absorption observed in froth could be used to retain all the samples above a pre-defined processability. Given that point spectrometers can currently be acquired for less than half the cost of an imaging system, we recommend the use of the former for future trials in operating environments.

The effect of oil under in‐situ conditions on the seismic properties of rocks

Geophysics ◽  
1992 ◽  
Vol 57 (7) ◽  
pp. 894-901 ◽  
Author(s):  
Virginia A. Clark
Keyword(s):  
Elastic Properties ◽  
Oil Sands ◽  
Velocity Of Sound ◽  
Oil Sand ◽  
Seismic Properties ◽  
In Situ Conditions ◽  
Reservoir Conditions ◽  
Seismic Sections ◽  
Seismic Anomalies

Direct hydrocarbon indicators (DHIs) on seismic sections are commonly thought to be diagnostic only of gas. However, oil sands can also generate DHIs such as bright spots and flat events since oils under in‐situ conditions can contain large amounts of solution gas. This dissolved gas substantially decreases the velocity of sound and the density of the oils as compared to measurements of these properties at surface conditions. Hydrocarbon indicators caused by oil sands are investigated by first measuring the elastic properties of an oil as a function of gas‐oil ratio, next, calculating the elastic properties of additional oil compositions under in‐situ conditions using standard pressure‐volume‐temperature (PVT) measurements, and then calculating the compressional velocity in oil‐saturated rocks for several typical oils using Gaasmann’s equation. The potential for seismic anomalies caused by oil‐saturated rocks is higher than thought because the properties of oil under reservoir conditions can differ significantly from those of surface oils. Specifically: 1) The properties of oil depend on its composition: the higher the API gravity and the gas‐to‐oil ratio (GOR), the lower the density and velocity of sound (adiabatic bulk modulus) and the lower the velocity of a rock saturated with the oil. 2) Calculations of oil‐sand velocities using the in situ properties of oils show that areas having light oils and/or poorly consolidated rocks are the most likely areas in which to encounter oil DHIs. Since overpressured areas can have both poorly consolidated rocks and high GOR oils, they are especially prone to large oil responses.

In Situ Viscosity of Oil Sands Using Low Field NMR

2005 ◽  
Vol 44 (09) ◽  
Author(s):  
J. Bryan ◽  
D. Moon ◽  
A. Kantzas
Keyword(s):  
Oil Sands ◽  
Low Field ◽  
Low Field Nmr

In Situ Viscosity of Oil Sands Using Low Field NMR

2003 ◽  
Author(s):  
J. Bryan ◽  
A. Kantzas ◽  
D. Moon
Keyword(s):  
Oil Sands ◽  
Low Field ◽  
Low Field Nmr

A Fundamental Understanding of Erosion-Corrosion of Hydrotransport Pipes in Oil Sands Slurry

2008 ◽  
Author(s):  
X. Tang ◽  
L. Y. Xu ◽  
Y. Frank Cheng
Keyword(s):  
Oil Sands ◽  
Impact Angle ◽  
Oil Sand ◽  
Water Emulsion ◽  
Flowing Fluid ◽  
Impingement Jet ◽  
Potentiodynamic Polarization Curves ◽  
Erosion Corrosion ◽  
Fundamental Understanding ◽  
Oil Water

Erosion-corrosion (E-C) of X-65 pipe steel was investigated in a simulated oil sand slurry through an impingement jet system. Measurements of weight-loss and potentiodynamic polarization curves combined with optical microscopy observation were performed to determine the synergism of corrosion and erosion in E-C of steel. It was found that passivity of the steel developed in static oil-water emulsion cannot be maintained in the flowing fluid due to the enhanced activity of the steel upon impingement of the emulsion/slurry. The effect of slurry impact angle on E-C of steel is complex, depending on the magnitude and synergism of shear stress and normal stress exerting on the electrode surface. There is a synergism of corrosion and erosion in E-C of steel. The contributions of corrosion and erosion to E-C rate of the steel in oil sand slurry rank approximately 30% and 70%, respectively. Erosion dominates the E-C of X-65 steel in oil sand slurry.

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