Experimental Study on Foamy Viscosity by Analysing CO2 Micro-Bubbles in Hexadecane

Sugai

et al. 2016

Can J Chem Eng

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Basic understanding of numerical modelling for the effects of CO2 foaming on heavy oil production behaviour using the huff‐and‐puff process is relevant for CO2‐EOR performance. The numerical model was constructed based on laboratory measurements: CO2 solubility, foam swelling, and apparent viscosity. The model for unsaturated solubility in porous media, such as sandstone cores and oil reservoirs, was proposed by defining CO2 solubility in heavy oil for generating foamy oil. The foaming process was modelled with four kinds of foamy oils at discrete depressurizations below each equilibrium pressure. A numerical model of apparent foam viscosity with discrete depressurization was set up based on experimental measurements as a function of pressures and temperatures of 0.1–10 MPa and 20–50 °C. The matching between the numerical simulations of heavy oil drainage and experimental measurements of foaming in Berea sandstone cores (Psat = 10 MPa at 50 °C) shows 31 % oil recovery after depressurization to atmospheric pressure. The numerical simulation results of heavy oil production at field‐scale showed that CO2 gas production quickly increases after depressurization and then the foamy oil production increases following the peak gas production rate. In the first cycle of the huff‐and‐puff process, the maximum oil production rate ranged from 4–68 m3/day. From the sensitivity study it can be concluded that the initial oil saturation and the CO2 dissolution zone as compared with reservoir size play a main function in heavy oil production by CO2 gas foaming in the huff‐and‐puff process.

Section: Resultsmentioning

confidence: 99%

“…The foaming mechanism starts during depressurization and its viscosity was measured for every step of depressurization. The complete procedure for generating foamy oil and measuring its viscosity were described by Or et al…”

Section: Resultsmentioning

confidence: 99%

Preliminary numerical modelling of CO₂ gas foaming in heavy oil and simulations of oil production from heavy oil reservoirs

Sugai

et al. 2016

Can J Chem Eng

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“…Additionally, it should be bear in mind that, despite the low concentration of gas in water, the reservoir environment may favor chemistry between the reservoir rock formation, brine, and carbon dioxide. Chemistry that invariably leads to scale formation (Kaszuba et al 2003;Nguele et al 2014). …”

Section: Phase Compositionmentioning

confidence: 99%

Pseudo-phase equilibrium of light and heavy crude oils for enhanced oil recovery

Nguele

J Petrol Explor Prod Technol

Ghulami

et al. 2015

Presented paper, herein, is on phase equilibrium of light and heavy crudes known to be closely related to enhanced oil recovery (EOR). In miscible gas injection, the advancing gas (or injecting fluid) develops with petroleum fluids a miscibility front in the reservoir fluids that further reduces the viscous forces holding crudes stranded. The present work presents a phase equilibrium scheme upon which heavy oil swelling and light crude vaporization were found when carbon dioxide (or methane) was used as advancing gas. Heavy crude swelling was observed to be not only dependent on gas solubility but also on the chemical composition of the crude oil. Although a small fraction of injecting gas was distributed in the reservoir water, the initial water-oil ratio was seen to alter the bubble-point pressure from 10 to 30 % depending of the injected gas. In order to mimic miscible-like behavior during gas injection, a dynamic description of methane and carbon dioxide was proposed. Alteration of PVT parameters below and beyond the bubble-point pressure was highlighted therefrom.

“…The procedure of foamy oil generation and measurement of its apparent viscosity were detailed by Or et al, [9].However, the effect of temperature of foamy oil viscosity was also considered since the depressurizing pressure creates adiabatic temperature. As combination of depressurizing pressure and temperature effects, a numerical modeling of apparent foamy viscosity can be created.…”

Section: Modeling Of Apparent Foamy Viscositymentioning

confidence: 99%

Numerical Simulation of CO2 Gas Microbubble of Foamy Oil

Sugai

et al. 2014

Energy Procedia

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Heavy oil production by CO2 gas foaming has been simulated with a function of depressurization pressure. The numerical simulation was carried out by using CMG-STARS TM and based on experimental physical properties of foamy oil such as foam swelling and apparent viscosity. The matching between the numerical simulations of heavy oil drainage and experimental measurements of foaming in Berea sandstone cores (Psat = 10 MPa at 50 ºC) shows 31% of oil recovery after depressurization to atmospheric pressure. The behavior of heavy oil production and production scheme were proposed with assuming the CO2 gas dissolution zone. The effect of initial oil saturation and CO2 dissolution zone are the controlling factors of heavy oil production.