Novel Techniques for Measuring Heavy-Oil Fluid Properties
- Nina Naireka Goodarzi (University of Calgary) | Jonathan Luke Bryan (University of Calgary) | An Thuy Mai (University of Calgary) | Apostolos Kantzas (University of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- September 2007
- Document Type
- Journal Paper
- 305 - 315
- 2007. Society of Petroleum Engineers
- 1.2.3 Rock properties, 5.3.2 Multiphase Flow, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 5.5 Reservoir Simulation, 4.3.3 Aspaltenes, 5.2 Reservoir Fluid Dynamics, 4.6 Natural Gas, 5.5.2 Core Analysis, 2.4.3 Sand/Solids Control, 5.8.5 Oil Sand, Oil Shale, Bitumen, 4.1.2 Separation and Treating, 5.6.2 Core Analysis, 3.2.5 Produced Sand / Solids Management and Control
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Investigating the properties of live heavy oil, as pressure declines from the original reservoir pressure to ambient pressure, can aid in interpreting and simulating the response of heavy-oil reservoirs undergoing primary production. Foamy oil has a distinctly different and more complex behavior compared to conventional oil as the reservoir pressure depletes and the gas leaves solution from the oil. Solution gas separates very slowly from the oil; thus, conventional pressure/volume/temperature (PVT) measurements are not trivial to perform. In this paper, we present novel experiments that utilize X-ray computerized assisted technology (CT) scanning and low field nuclear magnetic resonance (NMR) techniques. These nondestructive tomographic methods are capable of providing unique in-situ measurements of how oil properties change as pressure depletes in a PVT cell. Specifically, this paper details measurements of oil density, oil and gas formation volume factor, solution gas/oil ratio, (GOR), and oil viscosity as a function of pressure. Experiments were initially performed at a slow rate, as in conventional PVT tests, allowing equilibrium to be reached at each pressure step. These results are compared to non-equilibrium tests, whereby pressure declines linearly with time, as in coreflood experiments. The incremental benefit of the proposed techniques is that they provide more detailed information about the oil, which improves our understanding of foamy-oil properties.
Understanding fluid behavior of heavy oils is important for reservoir simulation and production response predictions. In heavy-oil reservoirs, the oil viscosity and density are commonly reported, but there is little experimental data in the literature reporting how oil properties change with pressure. This information would be especially useful for production companies seeking to understand and improve their primary (cold production) response.
It is already widely known that foamy-oil behavior is a major cause for increased production in cold heavy-oil reservoirs along with sand production. Therefore, it would be valuable to first study the bulk fluid properties of live heavy oil prior to sandpack-depletion experiments. If the response of these properties to incremental pressure reduction can be established, this can be compared with fluid expansion during pressure depletion in a sandpack.
CT scanning is useful in studying high-pressure PVT relationships. Images of a pressure vessel filled with live oil can be taken as the volume of the vessel is expanded and used to calculate bulk densities and free gas saturation. Also, CT images allow us to visually see where free gas is formed in the vessel. For example, CT scanning can be used to provide an indication of whether or not small bubbles nucleate within the oil and then slowly coalesce into a gas cap, or if free gas forms straight away.
CT scanning provides much more information than conventional PVT cells. Uncertainties about where gas is forming in the oil, its effect on oil properties, and transient behavior cannot be reconciled in conventional PVT cells. Also, from CT images, the formation of microbubbles could be inferred based on the density of the oil with the dissolved gas. If the oil density decreases below the bubblepoint pressure, then it is likely that gas has come out of solution but remains within the oil; therefore, the resulting mixture is less dense than the original live oil. However, if oil density increases as the gas evolves, then the oil does not contain small gas bubbles, and gas has separated from the oil.
Also, the free gas saturation growth with time, and comparison of images at equilibrium vs. immediately after the expansion of the vessel, can provide mass transfer information about gas bubble growth, supersaturation, and gravity separation.
When characterizing heavy oil and bitumen fluid properties, oil viscosity is one of the most important pieces of information that has to be obtained. The high viscosities of heavy oil and bitumen present a significant obstacle to the technical and economic success of a given enhanced oil recovery option. As a result, in-situ oil viscosity measurement techniques would be of considerable benefit to the industry.
In heavy-oil reservoirs that are undergoing primary production, this problem is further complicated by the presence of the gas leaving solution with the oil. Above the bubblepoint, the gas is fully dissolved into the oil; thus, the live oil exists as a single-phase fluid. Once the pressure drops below the bubblepoint and gas begins to leave solution, the oil viscosity behavior is no longer well understood. In addition to our CT analysis, this work also presents the use of low field NMR as a tool for making in-situ viscosity estimates of live and foamy oil. NMR spectra change significantly as pressure drops and gas leaves solution, and these changes can be correlated to physical changes in the oil viscosity.
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