Three experiments have been performed, injecting brine and polymer into a sand pack saturated with heavy oil. Each experiment was imaged with time lapse X-ray CT. The first two experiments, conducted in a medical scanner with a resolution of 350 μm, suggested important features below the scale of spatial resolution. The last experiment, performed in a synchrotron beamline with a resolution of 4.3 μm, provided a view of oil/water interactions on the scale of individual pores. Conventional theory holds that waterflooding is unstable with respect to the development of fingers, which push the oil ahead of them. "Sweep efficiency" can be improved by increasing the water viscosity with polymer, which reduces the mobility ratio and stabilizes the front. Waterflooding has been applied successfully to heavy oil, but the detailed mechanisms of recovery are not well understood. Breakthrough of water occurs quickly at the producer; most oil production occurs at high water cuts over a long period of time. The most striking feature of the medical scans was the absence of distinct fingers of high water saturation. The only identifiable, compact "front" consisted of saturation changes of 20% or less. Moreover, breakthrough occurred long before the front reached the production end of the pack. More surprisingly, water saturation was observed to increase everywhere throughout each experiment. The inference was that fingering, if present, was occurring at a scale below that of the resolution. The synchrotron scans did not reveal the expected pore scale fingering, but instead showed evidence of water transport entirely in wetting films. Residual blobs of connate water were observed to grow throughout, but never linked up to form fully water-saturated paths. The mechanism of oil mobilization was also quite different from the traditional picture. There was no scale at which oil was pushed ahead of a water front. Instead, isolated droplets of immobile water swelled, fed by films of water on the grain surfaces. These results do not rule out an eventual transition to a more conventional picture; only a few pore volumes were injected. But the path to that state may be different from what is usually assumed.
Solvent mass transfer plays a key role in a thermal gravity drainage process involving solvent. The diffusion coefficients of solvent in such a process are not well studied. This article presents the effective diffusion coefficients of solvent in bitumen‐saturated sands under high temperature/pressure conditions measured using a CT scanning technique. Experimental results show that the effective diffusion coefficient of n‐hexane in bitumen‐saturated sands varied with the solvent concentration or with the viscosity of solvent–bitumen mixture (i.e., De ∝ c0.4 or De ∝ μm−0.46). The solvent concentration weighted diffusion coefficient of n‐hexane in the bitumen under the condition 160–170°C/1,900 kPa had an order of magnitude of about 10−5 cm2/s for solvent volume concentration less than 0.2. The penetration distance of n‐hexane in bitumen‐saturated sands depended on the nonlinearity of diffusion and had a value of −2 cm after 1‐day diffusion. The stronger the nonlinearity of diffusion, the shorter the penetration distance.
The difficulties of accurately measuring thermal properties, such as thermal conductivity of fractured and/or vuggy rocks are well known. Many commercially available methods are suitable only for liquids or re-packed sands. Others either require samples to be fairly uniform or are potentially destructive due to sample size limitations. In-situ measurements are possible, but can be costly. It can also be affected by in-situ distributions of fluids in the fractures and vugs, such as water, oil and possibly gas. In order to adapt the highly non-uniform nature of the carbonate cores without having to create further destruction of these cores, we developed a non-destructive method for measuring thermal conductivity of highly vuggy and moderately fractured carbonate cores in their whole diameter. In this paper, we report the theoretical background of this methodology; laboratory observations of thermal behaviours; data analysis and resulting thermal conductivity values of carbonates cores. Using this method, we measured 20 cleaned carbonate cores (88 mm in diameter) from Grosmont C and D Formation in Saleski area. Measured thermal conductivity values ranged from 1.00 to 2.87 W/m·K in Grosmont C, and 0.82 to 3.16 W/m·K in Grosmont D. These values were determined to be a strong function of porosity rather than mineralogy, as the Grosmont Formation typically consists of greater than 95% dolomite. These measurements are also shown to be in good agreement with prior studies on non-fractured dolomite reservoirs. A correlation for thermal conductivity was derived which can be used for numerical simulation models.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.