Summary

When some heavy-oil reservoirs are produced using gas drive, they show three important features: low production gas/oil ratios, higher-than-expected production rates, and relatively high oil recovery. The mechanism for this unusual behavior remains controversial and poorly understood, though the term "foamy oil" is often used to describe such behavior. The impetus for this work stems from some recent projects performed in the Orinoco belt, Venezuela. There exist nearly one trillion bbl of heavy oil (oil in place) in this region on the basis of a recent evaluation. Two crucial issues must be addressed before or during designing production projects: What is a suitable method for evaluating the foamy-oil drive mechanism that plays a major role during such oil recovery, and how do we obtain a reasonable percentage of ultimate oil recovery? Unfortunately, it is still difficult to give good explanations for these two issues, although several studies were performed. This paper attempts to present better explanations for these two issues using experimental drainage in a long laboratory core in simulated reservoir conditions.

Our experiments show that ultimate oil recovery for the heavy oil in the Orinoco belt can be as high as 15-20%. This high recovery comes from three contributions: fluid and rock expansion, foamy-oil drive, and conventional-solution-gas drive. Approximately 3-5% of recovery is from fluid and rock expansion, 11-16% from foamy-oil drive, and 2-4% from conventional-solution-gas drive. This ultimate-oil-recovery percentage is much higher than the 12% that has been used in the field-development plan for the Orimulsion project. The experiments performed and their findings obtained in this paper are representative at least in the Orinoco belt region.

Introduction

Most practitioners try to produce as much oil as possible under primary recovery. In all solution-gas-drive reservoirs, gas is released from solution as the reservoir pressure declines. Gas initially exists in the form of small bubbles created within individual pores. As time evolves and pressure continues to decline, these bubbles grow to occupy the pores. With a further decline in pressure, the bubbles created in different locations become large enough to coalesce into a continuous gas phase. Conventional wisdom indicates that the discrete bubbles that are larger than pore throats remain immobile (trapped by capillary forces) and that gas flows only after the bubbles have coalesced into a continuous gas phase. Once the gas phase becomes continuous, which is equivalent to the gas saturation becoming larger than critical, the minimum saturation at which a continuous gas phase exists in porous media (Chen et al. 2006), traditional two-phase (gas and oil) flow with classical relative permeabilities occurs. A result of this evolution process is that the production gas/oil ratio (GOR) increases rapidly after the critical gas saturation has been exceeded.

Field observations in some heavy-oil reservoirs, however, do not fit into this solution-gas-drive description in that the production GOR remains relatively low. The recovery factors (percentage of the oil in a reservoir that can be recovered) in such reservoirs are also unexpectedly high. A simple explanation of these observations could be that the critical gas saturation is high in these reservoirs. This explanation cannot be confirmed by direct laboratory measurement of the critical gas saturation. An alternative explanation of the observed GOR behavior is that gas, instead of flowing only as a continuous phase, also flows in the form of gas-in-oil dispersion. This type of dispersed gas/oil flow is what is referred to as "foamy-oil" flow.

Although the unusual production behavior in some heavy-oil reservoirs was observed as early as the late 1960s, Smith (1988) appears to have been the first to report it and used the terms "oil/gas combination" and "mixed fluid" to describe the mixture of oil and gas that is entrained in heavy oil as very tiny bubbles. Baibakov and Garushev (1989) used the term "viscous-elastic system" to describe highly viscous oil with very fine bubbles present. Sarma and Maini (1992) were the first to use the phrase "foamy oil" to describe viscous oil that contains dispersed gas bubbles. Claridge and Prats (1995) used the terms "foamy heavy oil" and "foamy crude." Although there is continuing debate on the suitability of the term "foamy-oil flow" to describe the anomalous flow of the oil/gas mixture in primary production of heavy oil (Firoozabadi 2001; Tang and Firoozabadi 2003; Tang and Firoozabadi 2005), this expression has become a fixture in the petroleum-engineering terminology (Chen 2006, Maini 1996).

The actual structure of foamy-oil flow and its mathematical description are still not well understood. Much of the earlier discussion of such flow was based on the concept of microbubbles [i.e., bubbles much smaller than the average pore-throat size and, thus, free to move with the oil during flow (Sheng et al. 1999)]. This type of dispersion can be produced only by nucleation of a very large number of bubbles (explosive nucleation) and by the presence of a mechanism that prevents these bubbles from growing into larger bubbles with decline in pressure (Maini 1996). This hypothesis has not been supported by experimental evidence.

A more plausible hypothesis on the structure of foamy-oil flow is that it involves much larger bubbles migrating with the oil and that the dispersion is created by the breakup of bubbles during their migration with the oil. The major difference between the conventional-solution-gas drive and the foamy-solution-gas drive is that the pressure gradient in the latter is strong enough to mobilize gas clusters after they have grown to a certain size. Maini (1999) presented experimental evidence that supports this hypothesis for foamy-oil flow. This hypothesis seems consistent with the visual observations in micromodels that show the bubble size to be larger than the pore size. However, more laboratory experiments must be conducted to validate this hypothesis.

The impetus for this work stems from some recent projects performed in the Orinoco belt, Venezuela. The largest heavy-oil reserves in the world are in this region, with nearly one trillion bbbl of heavy oil in place on the basis of a recent evaluation (Fig. 1) (Andarcia et al. 2001). The unusual recovery performance mentioned previously has been observed during drainage of heavy-oil reservoirs in the Orinoco belt. The problems we now face are the following.

How will we estimate the production performance for the present project by taking into account the foamy-oil-drive mechanism? In addition, what will be an applicable measure to evaluate the production potential of this project?

What will a production profile of this project look like? How much oil will be produced within a certain time period of our operation?

Unfortunately, there were no satisfactory answers yet for these questions. This paper attempts to address these issues using results from a suite of laboratory experiments. The attempts to address these issues will improve our understanding of foamy-oil behavior and its mechanism.

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