An Experimental Investigation of the Effect of Temperature on Recovery of Heavy Oil From Diatomite
- G.-Q. Tang (Stanford U.) | A.R. Kovscek (Stanford U.)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- June 2004
- Document Type
- Journal Paper
- 163 - 179
- 2004. Society of Petroleum Engineers
- 4.3.3 Aspaltenes, 5.4.2 Gas Injection Methods, 1.2.3 Rock properties, 6.5.2 Water use, produced water discharge and disposal, 4.3.4 Scale, 5.4.10 Microbial Methods, 5.3.1 Flow in Porous Media, 1.6.9 Coring, Fishing, 5.5.2 Core Analysis, 5.3.2 Multiphase Flow, 4.1.2 Separation and Treating, 5.4.6 Thermal Methods, 5.4.1 Waterflooding, 5.1 Reservoir Characterisation, 4.1.5 Processing Equipment, 4.6 Natural Gas, 5.2.1 Phase Behavior and PVT Measurements
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An X-ray computed-tomography (CT) scanner, in combination with a novel high-temperature and high-pressure core holder, was used to investigate systematically heavy oil recovery from outcrop diatomite and field core. Temperatures ranged from 20 to 180°C, and all experiments are isothermal. Decane, two viscous white mineral oils, and heavy crude oil from the field were used as oil phases. In reservoir core filled with crude oil, oil recovery by spontaneous imbibition of water increased from 3% at 40°C (reservoir temperature) to 40% of oil in place at 180°C. Forced displacement brought total recovery to more than 50%. Thermal methods are effective at improving oil recovery from low-permeability, fractured oil-rock systems filled with moderate to viscous oil, whereas waterflood is not.
Recovery increases with temperature because oil viscosity decreases and wettability is altered toward water wetness. Increased imbibition rate and oil recovery corresponded with production of oil-wet fines at elevated temperature. A mechanism for increase in water wettability is proposed whereby fines detachment from pore surfaces increases the water-wet surface area.
The ultimate goal of this work is to improve our understanding of multiphase fluid and heat-flow characteristics of low-permeability, fractured rock. Oil production from many low-permeability, fractured reservoirs is frustrated by not only low matrix permeability but also by large oil viscosity and a matrix wettability state that is not sufficiently water-wet to favor water imbibition during conventional waterflooding (see Ref. 1). Some diatomaceous reservoirs appear to exhibit these attributes. Thermal recovery using hydraulically fractured wells is one process to improve oil recovery and unlock these resources. Steam injection is being tested in both drive2,3 and cyclic modes4,5 for light and heavy-oil diatomite reservoirs.
Virtually all recovery processes for diatomite and other tight fractured rocks rely to an extent on free and/or forced imbibition. 6 Capillary phenomena are equally important during steam injection into diatomite. Injected steam, especially at short times, is accompanied by condensation and flow of the resulting hot water away from the injector. In steamdrive, a condensed hot-water bank precedes the steam zone within the reservoir, whereas in cyclic steam operations the steam zone generally collapses during soak and production, leaving a region filled with heated oil and condensed steam. A necessary precursor to elucidating thermal oil recovery processes in diatomite is to understand the imbibition characteristics of hot water.
Diatomite is relatively unstudied in the laboratory. Most previous studies were performed on sandstone (see Refs. 7 through 10) or chalk (Refs. 11 and 12) at low temperature. Diatomite is fine-grained, exhibits a variety of pore length scales, and possesses complex flow pathways.6,13 Generalization of results across rock type from chalk or sandstone to diatomite is not currently possible. Further experiments probing the flow properties of this important class of rock are needed.
The first X-ray CT images of diatomite undergoing water injection were given by Wendel et al.14 Subsequently, spontaneous cocurrent6 and countercurrent15 imbibition characteristics were imaged with X-ray CT for a variety of mobility ratios at room temperature. Regardless of imbibition mode, oil was recovered at the laboratory scale at appreciable rates with sensibly zero pressure drop. On the other hand, Kamath et al.16 showed that water-oil relative-permeability endpoints could be increased by as much as 31% during forced displacement with increased flow rate and/or pressure drop.
This work studies experimentally the effect of temperature on water imbibition rate and ultimate recovery from oil-saturated core using diatomite from an outcrop and a heavy-oil field. The paper proceeds by discussing imbibition potential. It is a necessary tool for consistent interpretation of experimental results. Then, the high-pressure, high-temperature apparatus constructed to conduct spontaneous and forced imbibition experiments is described. Recovery data are interpreted using a dimensionless scaling group and an analytical model that exposes the role of wettability alteration, viscosity reduction, and oil/water interfacial tension.
When gravity is negligible, spontaneous water imbibition in oil-saturated porous media is driven solely by capillary pressure, Pc
where s=the interfacial tension between oil and water, r=the radius of curvature of the interface, and ?=the water/oil/solid contact angle. When the rock is strongly water-wetting, the contact angle is close to zero and interfacial tension dominates the capillary pressure for a given porous medium. Because the interfacial tension decreases with increasing temperature, temperature usually decreases the capillary pressure. This has a negative effect on water imbibition rate for a rock/water/oil system.
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