Determination of mass transfer parameters and swelling factor of CO2-oil systems at high pressures

Rezk, Mohamed Gamal; Foroozesh, Jalal

doi:10.1016/j.ijheatmasstransfer.2018.05.043

Cited by 49 publications

(28 citation statements)

References 31 publications

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“…CO 2 injection has been considered as an efficient enhanced oil recovery (EOR) technique that has been under many studies recently [1, 2, 3, 4, 5, 6, 7]. During CO 2 flooding projects, CO 2 as a greenhouse gas can also be stored underground through various storage mechanisms, which has made it to be a favorable EOR-Storage method.…”

Section: Introductionmentioning

confidence: 99%

Phase behavior and fluid interactions of a CO2-Light oil system at high pressures and temperatures

Rezk

Foroozesh

2019

Heliyon

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This paper investigates the phase behavior and mutual interactions between a light crude oil and CO 2 at high pressures and high temperatures (HPHT). To do so, we have measured PVT properties of the CO 2 -oil system at HPHT using a PVT setup. We have also tried to present a detailed methodology for measuring PVT properties of CO 2 -oil systems and highlight the difficulties such as oil vaporization by CO 2 during the experiments. A crude oil sample, collected from a Malaysian oil field, was used here. Our experiments indicated that, CO 2 solubility in the oil increased at higher pressures when measured at a fixed temperature. Our experiments also showed that increasing the test temperature would reduce CO 2 solubility in the oil, while its effect is more significant at higher pressures. The swelling factor (SF) measurements showed an increasing trend with pressure up to a certain value so-called extraction pressure, at which, the SF started to be reduced even became less than one. The measurements of oil viscosity indicated that CO 2 dissolution in the oil sample could reduce the mixture viscosity up to 61%. The interfacial tensions between CO 2 and the crude oil at different pressures were also measured while the results were used to estimate the minimum miscibility pressure (MMP) and the first contact miscibility (FCM) pressure. The IFT measurements at various pressures displayed a reduction trend as a result of more CO 2 dissolution in the oil but with two different slopes. That is, at lower pressure values, the measured IFTs were sharply reduced with pressure, while the reduction rate of the IFT became less when pressures exceeded the extraction pressure. This study helps with determining the optimum pressure and temperature conditions of CO 2 -oil systems to have a minimum IFT, a maximum CO 2 solubility and SF, and a minimum oil viscosity that are favorable for CO 2 -enhanced oil recovery projects. Additionally, the methodology presented here gives guidelines on how to design PVT experiments of CO 2 -oil systems for petroleum and chemical engineering applications.

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Section: Introductionmentioning

confidence: 99%

Phase behavior and fluid interactions of a CO2-Light oil system at high pressures and temperatures

Rezk

Foroozesh

2019

Heliyon

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“…The diffusion coefficients of CO 2 in more complicated systems have also been measured by several authors. This includes the recent work of Rezk and Foroozesh [8] who studied the diffusivity of CO 2 in crude oil using the pressure-decay method at T = 294 K. The diffusivity of CO 2 in crude oil have also been studied by Yang et al [9] and Guo et al [10]. Besides experimental work, molecular simulation techniques is an alternative tool for calculating diffusion coefficients, especially at conditions that are difficult to access in experimental work.…”

Section: Introductionmentioning

confidence: 99%

Diffusion Coefficients of Methane in Methylbenzene and Heptane at Temperatures between 323 K and 398 K at Pressures up to 65 MPa

Taib

Trusler

2020

Int J Thermophys

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We reported experimental measurements of the diffusion coefficient of methane at effectively infinite dilution in methylbenzene and in heptane at temperatures ranging from (323 to 398) K and at pressures up to 65 MPa. The Taylor dispersion method was used and the overall combined standard relative uncertainty was 2.3%. The experimental diffusion coefficients were correlated with a simple empirical model as well as the Stokes–Einstein model with the effective hydrodynamic radius of methane depending linearly upon the solvent density. The new data address key gaps in the literature and may facilitate the development of an improved predictive model for the diffusion coefficients of dilute gaseous solutes in hydrocarbon liquids.

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“…Moreover, the CO 2 transport in porous limestone rock core generates high temperature and typically, natural reservoir fines are easily detached at high temperatures and consequently, will lead to the permeability decline and well productivity loss as well (You et al 2016;Schembre and Kovscek 2005). Additionally, the plugged and bridged fines decline the fluid flow pressure and as a result, there will be a loss in the fluid momentum, where there will be a loss in the mass transfer coefficient (Rezk and Foroozesh 2018). Furthermore, CO 2 flow in carbonate reservoirs leads to mineral dissolution and precipitation, which overall reduces the permeability and fluid flow, and this is regardless of in situ fines migration (Khather et al 2019).…”

Section: Resultsmentioning

confidence: 99%

Subcritical CO2 effects on kaolinite fines transport in porous limestone media

Mahalingam¹,

Pranesh²,

Kanimozhi

et al. 2019

J Petrol Explor Prod Technol

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Carbonate reservoirs account for 60% share in global oil reserves, and CO 2-EOR process is employed in these carbonate fields for effective oil recovery and retention as well. Recent research reports that fines migration may lead to reservoir formation damage in oil bearing limestone and dolomite rocks. Although carbonate reservoirs are poor in clay minerals, some mass of clay fines existence in certain carbonate formations will cause severe damage to permeability and well productivity. This paper reports the single-phase flow of subcritical CO 2 in porous limestone rock core containing kaolinite clay fines. Fines are natural reservoir minerals (example, quartz) and clay particles such as kaolinite, illite, feldspar, smectite, and montmorillonite. But, this paper explores this CO 2-clay fines behavior in limestone rock as a function of kaolinite. So, two sets of core flood experiments were performed in the rock temperatures 120 °C and 160 °C. Initially, kaolinite clay has been injected into the limestone core in the form of suspension and then dried for hours in order to retain the solid fines in the internal pore chambers of the core. After that, the CO 2 under subcritical condition has been injected into the porous limestone core for fines mobilization and injected gas recovery. The major observations that are reported from the experimental tests are there is an increase in gas saturation for increasing injection time. Steady rise of heat transfer coefficient and enthalpy was noted for increasing gas saturation and time. Concentration of fines linearly soars with respect to elevating PVI and permeability declines for rising time. Pressure in the limestone core shows abnormal and nonlinear variation. Finally, gas discharge rate declines for increasing injection time. Experimental data are tested against the statistical model (regression), and the outcome indicated good agreement. Overall, this paper has successfully established the CO 2 effects on kaolinite clay fines behavior and its impact on oil recovery in carbonate fields.

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Determination of mass transfer parameters and swelling factor of CO2-oil systems at high pressures

Cited by 49 publications

References 31 publications

Phase behavior and fluid interactions of a CO2-Light oil system at high pressures and temperatures

Phase behavior and fluid interactions of a CO2-Light oil system at high pressures and temperatures

Diffusion Coefficients of Methane in Methylbenzene and Heptane at Temperatures between 323 K and 398 K at Pressures up to 65 MPa

Subcritical CO2 effects on kaolinite fines transport in porous limestone media

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