This paper describes a suite of alkali-surfactant (AS) floods that were performed in systems containing viscous heavy oil (11,500 mPa⋅s). The study investigates how AS injection can be used to generate oil and water emulsions, which can in turn lead to improved sweep efficiencies and oil recovery. Data is obtained from core flooding, with in-situ saturation measurements made using low field NMR. This work is applicable to the many heavy oil reservoirs in countries like Canada and Venezuela that contain viscous oil that still has some limited mobility under reservoir conditions. In previous studies, improved oil recovery compared to waterflooding was observed. This work provides additional information that can be used to better understand how chemical injection can lead to oil recovery.The core floods in this study indicate that emulsification is most efficient when used to block pre-formed water channels and improve the sweep efficiency of the flood. Both O/W and W/O emulsions may form in the same system, even under controlled salinity conditions. The re-distribution of water from the flooded channels into emulsified droplets in the oil is at least partially responsible for the pressure increase seen in these systems. W/O emulsification is accompanied by wettability alteration, as evidenced by the NMR spectra obtained. After the chemical flood is completed, it may be possible to restore the original water wet condition of the rock, which can provide potential for future non-thermal improved oil recovery.
This work details the results of ambient temperature waterfloods in unconsolidated sand containing heavy oil (11°API and viscosity of 11,500 mPa⋅s at 23°C). Experiments are performed at rates ranging from 0.4 -0.02 m/day, in sand with permeability of under 1 D to 9 D. By varying both the injection rate and the permeability of the sand, the relative influence of viscous and capillary forces can be determined. It is shown that by properly controlling the waterflood, significant heavy oil can still be recovered after water breakthrough has already occurred.The application of this work is for the significant heavy oil resource in Canada that exists in reservoirs that are too thin for thermal operations. A fraction of oil may initially be recovered through primary production, however at its conclusion a significant amount of oil still remains in the reservoir. Waterflooding is a simple process that has potential for recovery of additional oil, in reservoirs where more expensive options will not be possible.Due to the adverse mobility ratio between water and oil, water breakthrough occurs early in a waterflood, with a significant amount of the oil still being continuous at this time. The key to understanding the displacement of heavy oil by water is to consider the oil recovery after breakthrough. This oil is produced at high water cuts, and under negligible pressure gradients. Oil is therefore recovered by water imbibition into the water-wet sand. By varying the injection rates and the permeability of the sand, the importance of these capillary forces to oil recovery has been quantified.Capillary forces are generally deemed to be insignificant in heavy oil waterfloods due to the high oil viscosity. As such, concepts of viscous fingering and mobility ratio dominate discussions of heavy oil waterflood responses. In this work, it is shown that not only are capillary forces actually still important in heavy oil reservoirs, but in fact they are a significant mechanism responsible for oil recovery after water breakthrough. With this understood, heavy oil waterfloods can be properly designed to maximize flood efficiency and oil recovery.
Summary 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. Introduction 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.
fax 01-972-952-9435. AbstractLow 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.
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