Oil Recovery by Imbibition in Low-Permeability Chalk

Cuiec, L.; Bourbiaux, B.; Kalaydjian, F.

doi:10.2118/20259-pa

Cited by 131 publications

(94 citation statements)

References 12 publications

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“…Table 1 summarizes different forms of the viscosity term used in the literature. Lucas (1918), Gupta and Civan (1994), Behbahani and Blunt (2005), and Saboorian-Jooybari and Khademi (2014) used the wetting phase viscosity term in their equations and presented scaling groups similar to that of Mattax and Kyte (1962), whereas Iffly et al (1972), Cuiec et al (1994), Babadagli (1996), and Tavassoli et al (2005) used the nonwetting instead of the wetting phase viscosity. Ma et al (1997) experimentally observed that the imbibition time was proportional to the geometrical mean of wetting and nonwetting phase viscosities.…”

Section: Discussionmentioning

confidence: 99%

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Mirzaei‐Paiaman

Saboorian‐Jooybari

Masihi

2016

J Petrol Explor Prod Technol

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Wettability is a key parameter affecting petrophysical properties of reservoir rocks. Mirzaei-Paiaman et al. (Energy Fuels 27:7360-7368, 2013) presented an index (referred to as MPMS) for laboratory characterization of wettability of native-or restored-state reservoir rock samples. To use this index two counter-current spontaneous imbibition (COUCSI) experiments are needed, one on the native-or restored-state core sample and another on the strongly water-wet (SWW) reference system. Slope analysis of recovery data in these two systems gives inputs for determination of MPMS index. The two systems must have the same pore structure, initial water saturation, and viscosity ratio. The case of high viscosity reservoir crude needs the reference COUCSI test to be performed using a high viscosity polar compounds-free oil. Such test could be very slow and time consuming. The purpose of this study is to remove the need for limiting condition of the same viscosity ratio between the two systems, so that the reference experiment could be performed using any viscosity ratio independent of viscosity ratio of the native-or restored-state system. Thus, in the case of high viscosity reservoir crude, the reference test can be conducted using a low viscosity oil. Such test is relatively very fast and time efficient. We do this by benefiting the viscosity scaling group (VSG) proposed by Mason et al. (J Pet Sci Eng 72:195-205, 2010). Using experimental data from three sets of mixed-wet systems, we show that applicability of this VSG is not limited to SWW systems only. This VSG is used to relax the need for the limiting condition of the same viscosity ratio between the native-or restored-state and reference systems in the MPMS method. Using two sets of experimental data, we show that acceptable results are observed when comparing the MPMS indices estimated by the proposed technique and the original MPMS method.

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Section: Discussionmentioning

confidence: 99%

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Mirzaei‐Paiaman

Saboorian‐Jooybari

Masihi

2016

J Petrol Explor Prod Technol

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“…In the static conditions, matrix properties such as matrix permeability and size 2) , wettability 3) , rock heterogeneity, matrix boundary conditions, fluid properties such as density and the chemical structure of water 4) , interfacial tension 5) and viscosity ratio have become known to be effective parameters on the capil lary imbibition.…”

Section: Major Parameters Of Capillary Imbibition Mechanism In Nfrsmentioning

confidence: 99%

Experimental Investigation of Effective Parameters on Efficiency of Capillary Imbibition in Naturally Fractured Reservoirs

Sohi

Sola

Rashidi

2009

J. Jpn. Petrol. Inst.

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When a matrix is saturated by a non-wetting phase, and the wetting phase fills the fracture network, capillary imbibition may occur. Capillary imbibition can be an effective recovery mechanism in water wet naturally frac tured reservoirs (NFRs) where most of the oil is stored in tight matrix blocks. This paper presents the results and analysis of the laboratory experiments with variable parameters such as oil type, rock composition, temperature, permeability, porosity and fluid that invades the matrix. To investigate temperature effect on the efficiency of capillary imbibition mechanism, capillary imbibition tests were conducted under static conditions and at different temperatures, namely 22, 50 and 80℃ by using crude oils and carbonate samples taken from the same reservoirs. Also variable core sizes were used to study the block size effect on the oil recovery.The results of static imbibition experiments show that rock and oil properties are the dominant parameters in capillary imbibition. Furthermore, increasing the operational temperature also has a positive role in the process.Therefore, in thermal EOR methods, oil recovery increases due to the enhancement of the imbibition mechanism.Also the lighter oil show high sensitivity to capillary imbibition mechanism than the heavier one and using brine instead of pure water decreased the amount of oil recovery through capillary imbibition.

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“…The flow of the fluid in the cavity is free flow, and the flow of the fluid in the fractures and caves is described by the coupling of the seepage and the free flow. Discrete fracture cavity models [14][15][16] can reflect the development space of reservoirs, but it is highly dependent on the description technique of reservoirs. If considering the actual application and field staff training, the models do not have the advantages of application.…”

Section: Introductionmentioning

confidence: 99%

Well Test Analysis for Fractured and Vuggy Carbonate Reservoirs of Well Drilling in Large Scale Cave

et al. 2018

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Abstract:A well test analysis model for fractured and vuggy carbonate reservoir of wells drilling in large scale cave considering wellbore storage and skin factor is established in this paper. The Laplace transformation and Stehfest numerical inversion are applied to obtain the results of wellbore pressure. Through the sensitivity analysis of different parameters for the well test typical curves, it is found that the change of the well test curves is in accordance with the theoretical analysis. With the increase of skin factor, the hump of well test typical curves is steeper. The storage ratio influences the depth and width of the concave in the pressure derivative curves. The cross flow coefficient mainly affects the position of the concave occurrence in the pressure derivative curves. The dimensionless reservoir radius mainly affects the middle and late stages of the log-log pressure type curves, and the later well test curves will be upturned for sealed boundary. The duration of the early stage of the log-log curves will become longer when drilling in large scale cave. The effective well radius is increased to a certain extent, which is in full agreement with the conclusions in this paper. The size of the caves has the same effect on the well test typical curves as wellbore storage coefficient. Due to acidification, fracturing, and other reasons, the boundary of the cave will collapse. Therefore, considering the wellbore storage coefficient and skin effect is very important during well testing. However, the existing models for well testing of fractured and vuggy carbonate reservoir often ignore the wellbore storage coefficient and skin effect. For fractured and vuggy carbonate reservoirs of well drilling in large scale cave, the existing models are not applicable. Since the previous models are mostly based on the triple-porosity medium and the equivalent continuum. The well test model for well drilling in large scale cave of fracture-cavity carbonate reservoirs with wellbore storage coefficient and skin factor in this work has significant application value for oil field.

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Oil Recovery by Imbibition in Low-Permeability Chalk

Cited by 131 publications

References 12 publications

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Experimental Investigation of Effective Parameters on Efficiency of Capillary Imbibition in Naturally Fractured Reservoirs

Well Test Analysis for Fractured and Vuggy Carbonate Reservoirs of Well Drilling in Large Scale Cave

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