Observations of Heavy Oil Primary Production Mechanisms From Long Core Depletion Experiments

Goodarzi, N.N.; Kantzas, A.

doi:10.2118/2006-086

Cited by 6 publications

(6 citation statements)

References 14 publications

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“…It is evident that primary production of heavy oil is related to the viscous forces present in the system, and if higher pressure gradients can be obtained (for a given system permeability and oil viscosity), higher primary recovery factors will be expected. The oil recovery obtained in these short cores is significantly larger than what can be achieved in longer core systems (17,18) , however, these cores are still valuable for post-cold production studies. Due to the high primary recovery in these systems, there are large areas of low oil/high gas saturation in contact with areas of higher oil saturation, and the core pressures were depleted during primary production.…”

Section: Primary Production: Experimental Resultsmentioning

confidence: 99%

“…Laboratory-scale investigations of solution gas drive in heavy oils requires the application of high depletion rates in order to match the observations made in the field. At longer length scales, it becomes more difficult for pressure gradients to develop across the entire physical model (16)(17)(18) , meaning that gas evolution and foamy oil flow is in fact a localized phenomenon (17,18) .…”

Section: Primary Production In Laboratory Coresmentioning

confidence: 99%

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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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107

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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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Section: Primary Production: Experimental Resultsmentioning

confidence: 99%

Section: Primary Production In Laboratory Coresmentioning

confidence: 99%

Insights Into Non-Thermal Recovery of Heavy Oil

Mai

Bryan

Goodarzi

et al. 2009

Journal of Canadian Petroleum Technology

Self Cite

107

View full text Add to dashboard Cite

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“…Another thing which needs to be kept in mind is that the position of the transducer close to production end (P12) for the sandpack core was changed after primary production of Goodarzi and Kantzas (2008). It was at the production end, next to BPR, but now it is at the 10 m distance to the production end.…”

Section: Resultsmentioning

confidence: 99%

“…CT scanner images were used to provide information about the evolution of gas. Goodarzi and Kantzas (2008) found different production behavior for the glassbeads core and the sandpack core. For the sandpack core, which has low permeability, scatter between the pressures along the core length has been observed in the single phase region above the bubble point.…”

Section: Summary Of Previous Production Historymentioning

confidence: 86%

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Enhanced Heavy Oil Recovery on Depleted Long Core System by CH4 and CO2

Shi

Kantzas

2008

International Thermal Operations and Heavy Oil Symposium

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This paper describes a laboratory study of potential post-cold production strategies for heavy oil reservoirs. The tests were conducted on two primarily depleted long core systems (glassbeads core and sandpack core). The glassbeads core is 18.2 m in length with higher permeability (11.8 Darcy) and the sandpack core is 18.5 m long with lower permeability (1.9 Darcy). Both core systems were recharged by CH 4 injection followed by a depletion step similar to the cold production experiment. Both cores were then exposed to a single cycle of CO 2 injection, soaking and production. This work aims at further understanding the heavy oil solution gas drive mechanism. Furthermore, the study aims at assessing methane and carbon dioxide recharging as a potential recovery method for heavy oil reservoirs, and at establishing a base line for comparison against each other. Results of this study indicate that CH 4 and CO 2 recharge processes give an additional 8% and 9% OOIP recovery for the glassbeads core and the sandpack core, respectively. Since the cold production for the glassbeads core (22.2% OOIP) was high, the low recharge recoveries may be pessimistic. However, for the sandpack core, the recharge recovery appears more optimistic with almost similar recovery to that of cold production (about 10.2% OOIP).

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