Solution-Gas Drive in Heavy Oil: Field Prediction and Sensitivity Studies Using Low Gas Relative Permeability

Kumar, Raushan; Pooladi‐Darvish, Mehran

doi:10.2118/02-03-01

Cited by 20 publications

(7 citation statements)

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“…Once pressure dropped below the supersaturation point of the core, the pressure drop across the core increased sharply and the oil flow rate correspondingly increased as well. All three core systems demonstrated this same behaviour, which has also been observed by other researchers (10)(11)(12)(13)(14)(15) . Figure 2 shows an example of the pressure and solution gasoil-ratio (GOR) response in the short core system.…”

Section: Primary Production: Experimental Resultssupporting

confidence: 89%

“…It has also been observed (10,11) that the pressure decline rate can also lead to differences in the final distribution of gas and the gas relative permeability. These observations have led to the development of pressure gradient-dependent or capillary number-dependent gas relative permeability curves (12)(13)(14)(15) .…”

Section: Primary Production In Laboratory Coresmentioning

confidence: 93%

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Insights Into Non-Thermal Recovery of Heavy Oil

Mai

Bryan

Goodarzi

et al. 2009

Journal of Canadian Petroleum Technology

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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Section: Primary Production: Experimental Resultssupporting

confidence: 89%

Section: Primary Production In Laboratory Coresmentioning

confidence: 93%

Insights Into Non-Thermal Recovery of Heavy Oil

Mai

Bryan

Goodarzi

et al. 2009

Journal of Canadian Petroleum Technology

106

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“…The gas-oil flow in heavy oil systems has been widely studied based on heavy oil solution gas drive (Kumar et al, 2002;Ostos et al, 2004;Maini et al, 2010).…”

Section: Gas-oil Flow In Csi Versus In Heavy Oil Solution Gas Drivementioning

confidence: 99%

Characterization of gas-oil flow in Cyclic Solvent Injection (CSI) for heavy oil recovery

Hong

Zeng

2017

Journal of Petroleum Science and Engineering

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Sam Yeol Hong, candidate for the degree of Master of Applied Science in Petroleum Systems Engineering, has presented a thesis titled, Characterization of Gas-Oil Flow in Cyclic Solvent Injection (CSI) for Heavy Oil Recovery, in an oral examination held on July 28, 2016. The following committee members have found the thesis acceptable in form and content, and that the candidate demonstrated satisfactory knowledge of the subject material.

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“…1) Equivalent Permeability Models: In these models, the production of sand was thought to lead to the development of a radial higher permeability (dilated) zone which would start at the vertical well and grow into the formation (2)(3)(4)(5) . 1) Equivalent Permeability Models: In these models, the production of sand was thought to lead to the development of a radial higher permeability (dilated) zone which would start at the vertical well and grow into the formation (2)(3)(4)(5) .…”

Section: Introductionmentioning

confidence: 99%

“…The earlier models assumed that the permeability of the dilated zone was constant (2) . Kumar and Pooladi-Darvish (4) went further in this approach by also history matching the sand production from a typical cold production well. Kumar and Pooladi-Darvish (4) went further in this approach by also history matching the sand production from a typical cold production well.…”

Section: Introductionmentioning

confidence: 99%

Modelling of Sand Transport Through Wormholes

Tremblay¹

2005

Journal of Canadian Petroleum Technology

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One of the key mechanisms in the cold production (CHOPS) process is the development of high permeability channels (wormholes), which increase the access to the reservoir. In order to model the growth of wormholes in the field, it is necessary to predict the flow of sand along the wormholes. The laminar flow of sand and oil through an open channel within a wormhole was modelled using an analytical Bingham Mohr-Coulomb model. This model was tested by comparing its predictions to oil and sand flow rate measurements obtained in pipe flow experiments reported in the literature. The model for sand transport was used in developing a field wormhole growth model. Introduction In Western Canada, well operators have observed that encouraging sand production along with the oil, in primary recovery, can lead to the economical production of heavy oil from thin reservoirs. Field tests and laboratory experiments suggest that the enhanced recovery associated with massive sand production can best be explained by the development of high permeability channels (wormholes), which access the reservoir(1). The existing cold production models can be essentially divided into three groups.Equivalent Permeability Models: In these models, the production of sand was thought to lead to the development of a radial higher permeability (dilated) zone which would start at the vertical well and grow into the formation(2–5). The earlier models assumed that the permeability of the dilated zone was constant(2). Denbina et al.(3) concluded that both a dynamically enhanced absolute permeability of the formation with sand production and a suppressed gas relative permeability were required to history match the oil production from typical cold production wells. Kumar and Pooladi-Darvish(4) went further in this approach by also history matching the sand production from a typical cold production well. Wang and Chen(5) developed a cold production model which also takes into account the sand transport within wormholes. They history matched the cumulative oil and sand for a typical cold production well.Wormhole Network (Fractal) Models: In this category of models, the enhanced permeability zone caused by sand production is assumed to be caused by a fractal network of wormholes(6–9). The number and density of the wormhole network was assumed to be large enough such that on a larger scale, the region from which sand is produced can be assumed to be uniform. This required that the wormholes be small and that significant branching occur. Reasonable history matches of the oil and sand production rates were obtained for a set of cold production wells(8). Tan et al.(6) also matched the temperature in producing wells during steam injection. The wormhole network was modelled using the Diffusion Limited Aggregation (DLA) fractal geostatistical approach. A semi-analytical cold production model based on a fractal distribution of wormholes was also developed by Liu and Zhao(9).Linear Channel Models: Loughead and Saltuklaroglu(10) interpreted the pressure build-up tests in cold production wells as indicative of linear flow through a high permeability channel.

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Solution-Gas Drive in Heavy Oil: Field Prediction and Sensitivity Studies Using Low Gas Relative Permeability

Cited by 20 publications

References 0 publications

Insights Into Non-Thermal Recovery of Heavy Oil

Insights Into Non-Thermal Recovery of Heavy Oil

Characterization of gas-oil flow in Cyclic Solvent Injection (CSI) for heavy oil recovery

Modelling of Sand Transport Through Wormholes

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