The Effect of Scale on the Primary Depletion of Heavy Oil Solution Gas Drive

Goodarzi, N.N.; Kantzas, Apostolos

doi:10.2118/2006-087

Cited by 4 publications

(2 citation statements)

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“…the oil saturation is lower) closer to the production end. This saturation gradient is even more evident in longer core systems 16 . Overall, however, it is evident that there is a free gas fraction ranging from approximately 0.18 -0.30 all along the length of the core.…”

Section: Secondary Waterfloodmentioning

confidence: 90%

“…This implies that gas leaves solution all over the core, which was also previously measured in bulk liquid studies 15 . This is a function of the relatively small scale of these experiments; in longer core systems gas will only leave solution in the regions close to the production end of the core 16 . In the reservoir, therefore, if water is injected into zones far from the production wells, the situation may be similar to that of the gas-free oil studies shown previously.…”

Section: Secondary Waterfloodmentioning

confidence: 99%

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Mechanisms of Heavy Oil Recovery by Low Rate Waterflooding

Mai¹,

Kantzas²

2008

Canadian International Petroleum Conference

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At the conclusion of primary heavy oil production, significant volumes of oil still remain in the reservoir under depleted reservoir pressure. Waterfloods are often considered for additional oil recovery. It is accepted that conventional oil waterflooding theory is not applicable for heavy oil. However, there is a lack of understanding of how waterfloods should perform in these reservoirs, particularly after water breakthrough. In this study, waterfloods were performed at multiple rates in cores containing heavy oil and connate water. In some cores oil was initially free of solution gas, and waterfloods were a primary recovery process. In other cores, waterfloods were performed after primary production. Experiments were performed in linear systems for a highviscosity oil (11,500 mPa⋅s), at different injection rates. The influence of viscous and capillary forces is studied in primary vs. secondary recovery systems. A common misconception is that capillary forces are negligible in heavy oil; however this work shows that these forces are significant, and that water imbibition after water breakthrough can lead to improved oil recovery in both primary and secondary waterfloods. PETROLEUM SOCIETY

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Section: Secondary Waterfloodmentioning

confidence: 90%

Section: Secondary Waterfloodmentioning

confidence: 99%

Mechanisms of Heavy Oil Recovery by Low Rate Waterflooding

Mai¹,

Kantzas²

2008

Canadian International Petroleum Conference

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Experimental study and new three-dimensional kinetic modeling of foamy solution-gas drive processes

Sun

Zhang

Wang

et al. 2018

Sci Rep

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Foamy solution-gas drive processes in heavy oil reservoirs are very complex. The influence of some microscopic factors on this process is not fully understood due to limitations of traditional depletion tests. This study aims to investigate foamy solution-gas drive by experiments and simulations. First, the effects of the pressure depletion rate on critical gas saturation and foamy solution-gas drive processes were investigated by laboratory experiments. Second, a new three-dimensional foamy oil model that captures many important characteristics of foamy solution-gas drive, such as non-equilibrium behavior, gas evolution kinetics, and the effect of viscous forces on gas mobility, was developed. Last, the effects of some important parameters on foamy solution-gas drive were systematically investigated,and a model application was conducted in a typical foamy oil reservoir. The results indicate that the new model is capble of simulating many of the unusual behaviors observed in foamy solution-gas drive on a laboratory and field scales. High oil recoveries were obtained with a high oil viscosity, high depletion rate, long sandpack, and low solution gas-oil ratio. Foamy solution-gas drive processes are sensitive to the depletion rate, length, and critical gas saturation. The oil viscosity, solution GOR and diffusion coefficient are not sensitive factors.

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Insights Into Non-Thermal Recovery of Heavy Oil

Mai

Bryan

Goodarzi

et al. 2009

Journal of Canadian Petroleum Technology

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106

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Many heavy oil reservoirs contain oil that has some limited mobility under reservoir conditions. In these reservoirs, a small fraction of the oil-in-place can be recovered using the internal reservoir energy through heavy oil solution gas drive (primary production). An integral part of this process is the so-called 'foamy oil mechanism', whereby oil is produced as a gas-in-oil dispersion. At the end of primary production, the bulk of the oil is still in place, while the natural energy of the reservoir has been depleted. This remaining oil is still mostly continuous and presents a valuable target for further recovery. Many of these reservoirs are relatively small or thin, or may be contacted by overlying gas or underlying water. As such, they are poor candidates for thermal oil recovery methods, so any additional oil recovery after primary production must be non-thermal. In this work, we present experimental results of foamy oil depletion at two different length scales and varying depletion rates. Tests were conducted in the absence of sand production, and the results from the depletion experiments are interpreted in terms of viscous forces. At the conclusion of primary recovery, the potential for further non-thermal exploitation of these reservoirs is explored. Results for waterflooding and chemical flooding are presented, demonstrating the viability of these techniques for heavy oil EOR. Several displacement mechanisms are identified through the secondary and tertiary processes that contribute to significant (although potentially slow) incremental recovery of heavy oil. Introduction Many countries have heavy oil reservoirs. Canada and Venezuela in particular contain some of the largest heavy oil and bitumen resources in the world. Rising energy demands, coupled with a decline in conventional oil reserves, has led to increased interest in heavy oil recovery in recent years. The size of these heavy oil deposits is considerable, and with volatile crude oil prices making it difficult to produce from some higher viscosity bitumen reservoirs, production of heavy oil could potentially be very important in years to come. Understanding the mechanisms by which heavy oil can be displaced in reservoirs is crucial to the successful recovery of this resource base. Heavy oil can be defined as a class of oils with viscosity ranging from 50 mPa.s up to around 50,000 mPa.s. This oil has limited mobility under reservoir temperature and pressure, and Darcy's Law predicts that the oil can flow slowly under high applied pressure gradients. However, it has been observed that in these reservoirs, solution gas drive leads to significantly higher rates and recoveries than what was expected by conventional understanding of gas-oil relative permeability behaviour(1). This behaviour, first reported in Canadian heavy oil, has since been observed in many other reservoirs around the world including South America, China and Albania. Investigations into the causes of this abnormal, but fortuitous, primary production response have been the focus of many publications in the past 25 years. The recovery from primary production in heavy oil reservoirs may be as high as 20%(2), but is usually lower.

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The Effect of Scale on the Primary Depletion of Heavy Oil Solution Gas Drive

Cited by 4 publications

References 0 publications

Mechanisms of Heavy Oil Recovery by Low Rate Waterflooding

Mechanisms of Heavy Oil Recovery by Low Rate Waterflooding

Experimental study and new three-dimensional kinetic modeling of foamy solution-gas drive processes

Insights Into Non-Thermal Recovery of Heavy Oil

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