Heavy-Oil Solution Gas Drive in Consolidated and Unconsolidated Rock

Summary Solution gas drive is effective to recover heavy oil from some reservoirs. Characterization of the relevant recovery mechanisms, however, remains an open question. In this work, we present an experimental study of the solution gas drive behavior of a 9°API crude oil with an initial solution gas/oil ratio (GOR) of 105 scf/STB and live-oil viscosity of 258 cp at 178°F. Constant rate depletions are conducted in a composite core (consolidated) and a sandpack (unconsolidated). The sandpack does not employ a confining pressure, whereas the consolidated core does. The evolution of in-situ gas saturation vs. pressure is monitored in the sandpack using X-ray computed tomography. The two different porous media allow us to develop a mechanistic perspective whereby the effects of depletion rate and overburden pressure on heavy-oil solution gas drive are investigated. The results are striking. They show that the overburden pressure offsets partially the pore-pressure decline. This compaction, in turn, modifies the size and shape of mobile gas bubbles, and as a result the oil and gas relative permeabilies are greater within the confined, consolidated core. Additionally, the supersaturation in the sandpack is markedly larger, but recovery is greatest from the composite core at identical rates as a result of compaction. Introduction Solution gas drive in some heavy-oil reservoirs yields unexpectedly large oil recovery. Remarkably, the reservoir pressure declines more slowly than expected and the produced GOR increases slowly below the equilibrium bubblepoint pressure. Since 1988, when Smith identified the phenomenon (commonly referred to as foamy oil), experimental and theoretical studies have aimed to elucidate gas-flow and oil-production mechanisms. Results indicate that the factors governing the efficiency of heavy-oil solution gas drive are oil viscosity (Tang and Firoozabadi 2003, 2005), depletion rate (Tang et al. 2006; Kumar et al. 2000; Sahni et al. 2004), solution GOR (Tang and Firoozabadi 2003), oil composition (Tang et al. 2006; Bauger et al. 2001), and gas-bubble morphology (Li and Yortsos 1995; Tang et al. 2006). Obviously, these factors are not mutually exclusive. Among them, depletion rate as well as the size and shape of bubbles play a key role in recovery. Additionally, the oil composition is important because it plays a determining role in the flowing gas-bubble size that ultimately determines gas-phase mobility (Tang et al. 2006). Gas bubbles grow as a result of supersaturation (the difference between equilibrium and dynamic pressure) as well as pressure depletion. Gas-bubble nucleation is usually described as progressive or instantaneous (Li and Yortsos 1995; Firoozabadi and Kashchiev 1996), depending on the oil composition and porous medium (Tang et al. 2006; Kumar et al. 2000). Experiments with (El Yousfi et al. 1997; George et al. 2005) and simulation of (Arora and Kovscek 2003) gas nucleation in porous media indicate that the gas phase forms progressively. The period of active bubble nucleation is, however, relatively short compared to the time needed to deplete the sysem. Therefore, the process might be approximated as instantaneous nucleation if the longer time behavior is of interest (El Yousfi et al. 1997).

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A New Model to Obtain Representative Field Relative Permeability for Reservoirs Produced under Solution Gas Drive

SPE Reservoir Evaluation & Engineering ◽

10.2118/84543-pa ◽

2005 ◽

Vol 8 (04) ◽

pp. 348-356 ◽

Cited By ~ 2

Author(s):

Fabrice Bauget ◽

Patrick Egermann ◽

Roland Lenormand

Keyword(s):

Relative Permeability ◽

History Matching ◽

Phase Transfer ◽

Bubble Nucleation ◽

Relative Permeabilities ◽

Solution Gas Drive ◽

Reservoir Conditions ◽

Depletion Rate ◽

Gas Drive ◽

Solution Gas

Summary Relative permeability curves (kr) control production and are of primary importance for any type of recovery process. In the case of production by displacement (waterflood or gasflood), the kr curves obtained in the laboratory can be used in numerical simulators to predict hydrocarbon recovery (after upscaling to account for heterogeneity). In the case of reservoirs produced under solution-gas drive (depressurized field, foamy oils), the experiments conducted in the laboratory depend on the depletion rate and cannot be used directly for reservoir simulations. We have developed a novel approach for calculating representative field relative permeabilities. This new method is based on a physical model that takes into account the various mechanisms of the process: bubble nucleation(pre-existing bubbles model), phase transfer (volumetric transfer function), and gas displacement (bubble flow). In our model, we have identified a few"invariant" parameters that are not sensitive to depletion rate and are specific to the rock/fluid system (mainly the pre-existing bubble-size distribution and a proportionality coefficient relating gas and oil velocity for the dispersed-phase regime). These invariant parameters are determined by history matching one experiment at a given depletion rate. The calibrated model is then used to generate synthetic data at any depletion rate, especially at very low depletion rates representative of the reservoir conditions. Relative permeabilities are derived from these"numerical" experiments in the same way as they are from real experiments. The calculated kr is finally used in commercial reservoir simulators. We have tested our model by using several series of published experiments with light and heavy oils. After adjusting the invariant parameters on one or two experiments, we are able to predict other experiments performed at different depletion rates with very good accuracy. Finally, we present an example of determination of relative permeabilities at reservoir depletion rates. Introduction In the case of conventional recovery processes (waterflooding and gasflooding), experiments that are conducted in the laboratory can mimic the conditions that prevail in the reservoir. Hence, the kr data derived from these experiments can be used in a practically straightforward manner for field-simulation purposes (upscaling is often needed to account for heterogeneities). The problem is more complicated for recovery by solution-gas drive. In this case, the laboratory experiments fail in reproducing the reservoir conditions. In reservoirs, the depletion rates are at least several times lower than what can be obtained in the laboratory. Because the depletion rate controls the gas topology (bubble density), the diffusion of gas from solution (out of equilibrium), and the gas displacement (dispersed flow), it also dramatically affects the shape of the kr curves. Therefore, the depletion experiments cannot be used to derive field kr data directly.

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Effect of Depletion Rate on Gas Mobility and Solution Gas Drive in Heavy Oil

SPE Journal ◽

10.2118/78438-pa ◽

2002 ◽

Vol 7 (02) ◽

pp. 213-220 ◽

Cited By ~ 17

Author(s):

R. Kumar ◽

M. Pooladi-Darvish ◽

T. Okazawa

Keyword(s):

Heavy Oil ◽

Solution Gas Drive ◽

Depletion Rate ◽

Gas Mobility ◽

Gas Drive ◽

Solution Gas

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Effect of Depletion Rate on Performance of Solution Gas Drive in Heavy Oil Systems

10.2118/81114-ms ◽

2003 ◽

Cited By ~ 12

Author(s):

Brij B. Maini

Keyword(s):

Heavy Oil ◽

Solution Gas Drive ◽

Depletion Rate ◽

Gas Drive ◽

Solution Gas

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An Investigation of the Effect of Oil Composition on Heavy Oil Solution-Gas Drive

10.2118/84197-ms ◽

2003 ◽

Cited By ~ 2

Author(s):

G.-Q. Tang ◽

T. Leung ◽

L.M. Castanier ◽

A. Sahni ◽

F. Gadelle ◽

...

Keyword(s):

Heavy Oil ◽

Oil Composition ◽

Solution Gas Drive ◽

Gas Drive ◽

Solution Gas

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An Investigation of the Effect of Oil Composition on Heavy Oil Solution-Gas Drive

SPE Journal ◽

10.2118/84197-pa ◽

2006 ◽

Vol 11 (01) ◽

pp. 58-70 ◽

Cited By ~ 11

Author(s):

Guo-Qing Tang ◽

Yi Tak Leung ◽

Louis M. Castanier ◽

Akshay Sahni ◽

Frederic Gadelle ◽

...

Keyword(s):

Crude Oil ◽

Gas Phase ◽

Heavy Oil ◽

Gas Bubbles ◽

Gas Saturation ◽

Mineral Oils ◽

Solution Gas Drive ◽

Depletion Rate ◽

Gas Drive ◽

Solution Gas

Summary This study probes experimentally the mechanisms of heavy-oil solution gas drive through a series of depletion experiments employing two heavy crude oils and two viscous mineral oils. Mineral oils were chosen with viscosity similar to crude oil at reservoir temperature. A specially designed aluminum coreholder allows visualization of gas phase evolution during depletion using X-ray computed tomography (CT). In addition, a visualization cell was installed at the outlet of the sandpack to monitor the flowing-gas-bubble behavior vs. pressure. Bubble behavior observed at the outlet corroborates CT measurements of in-situ gas saturation vs. pressure. Both depletion rate and oil composition affect the size of mobile bubbles. At a high depletion rate (0.035 PV/hr), a foam-like flow of relatively small pore-sized bubbles dominates the gas and oil production of both crude oils. Conversely, at a low depletion rate (0.0030 PV/hr), foam-like flow is not observed in the less viscous crude oil; however, foam-like flow behavior is still found for the more viscous crude oil. No foam-like flow is observed for the mineral oils. In-situ imaging shows that the gas saturation distribution along the sandpack is not uniform. As the pattern of produced gas switches from dispersed bubbles to free gas flow, the distribution of gas saturation becomes even more heterogeneous. This indicates that a combination of pore restrictions and gravity forces significantly affects free gas flow. Additionally, results show that solution-gas drive is effective even at reservoir temperatures as great as 80°C. Oil recovery ranges from 12 to 30% OOIP; the higher the depletion rate, the greater the recovery rate. Introduction Solution gas drive has shown unexpectedly high recovery efficiency in some heavy-oil reservoirs. The mechanisms, however, that have been proposed are speculative, sometimes contradictory, and do not explain fully the origin of high primary oil recovery and slow decline in reservoir pressure. Smith (1988) first identified this effect. He hypothesized that gas bubbles smaller than pore constrictions are liberated from the oil, but are not able to form a continuous gas phase and flow freely. Instead, the gas bubbles exist in a dispersed state in the oil and only flow with the oil phase. Smith stated that oil viscosity is reduced significantly, resulting in high recovery performance. Later, many researchers focused on so-called foamy-oil behavior. Claridge and Prats (1995) hypothesized that heavy-oil components (such as asphaltenes) concentrate at the interfaces between oil and gas bubbles, thereby preventing bubbles from coalescing into a continuous gas phase. Bubbles are assumed to be smaller than pore dimensions. Claridge and Prats stated that the concentration of heavy-oil components at the interfaces results in a reduction of the viscosity of the remaining oil. Bora et al. (2000) discussed the flow behavior of solution gas drive in heavy oils. Based on their studies, they found that dispersed gas bubbles do not coalesce rapidly in heavy oil, especially at high depletion rate. They stated that the main feature of the gas/oil dispersion is a reduced viscosity compared to the original oil. Models to explain the experimental results were also established (Sheng et al. 1994, 1996, 1999, 1995).

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