Pore-scale imaging with measurement of relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions

Gao, Ying; Raeini, Ali Q.; Selem, Ahmed M.; Bondino, Igor; Blunt, Martin J.; Bijeljic, Branko

doi:10.1016/j.advwatres.2020.103786

Cited by 40 publications

(30 citation statements)

References 45 publications

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“…This redistribution has not been captured in previous studies 42 and is consistent with a shift towards more water-wet conditions. This fluid configuration where both oil and brine fill large and small pores is consistent with a mixed-wet state with both oil-wet and water-wet regions of the rock 6 , 36 , 61 , 62 : brine preferentially displaced oil from the smaller water-wet elements, while oil filled larger pores. In regions of the pore space that remained oil-wet, oil was not displaced until the flow rate was increased.…”

Section: Resultssupporting

confidence: 75%

“…When the interfaces have two negative principal curvatures, i.e. positive Gaussian curvature, this indicates an oil-wet system with the water phase poorly connected in the pore space 64 ; an opposite of what is observed in water-wet cases 36 . After LSW, the majority of the curvatures have one positive and one negative value, i.e.…”

Section: Resultsmentioning

confidence: 92%

“…7 b. This implies a mixed-wet system with good connectivity of the phases in the pore space 36 , 37 , 64 which results in enhanced oil flow and better recovery.

Figure 7 Measured oil–brine curvature distribution before and at the end of waterflooding using the principal curvatures (κ 1 and κ 2 ) obtained from all oil–brine interfaces.…”

Section: Resultsmentioning

confidence: 99%

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Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions

Selem

Agenet

Gao

et al. 2021

Sci Rep

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X-ray micro-tomography combined with a high-pressure high-temperature flow apparatus and advanced image analysis techniques were used to image and study fluid distribution, wetting states and oil recovery during low salinity waterflooding (LSW) in a complex carbonate rock at subsurface conditions. The sample, aged with crude oil, was flooded with low salinity brine with a series of increasing flow rates, eventually recovering 85% of the oil initially in place in the resolved porosity. The pore and throat occupancy analysis revealed a change in fluid distribution in the pore space for different injection rates. Low salinity brine initially invaded large pores, consistent with displacement in an oil-wet rock. However, as more brine was injected, a redistribution of fluids was observed; smaller pores and throats were invaded by brine and the displaced oil moved into larger pore elements. Furthermore, in situ contact angles and curvatures of oil–brine interfaces were measured to characterize wettability changes within the pore space and calculate capillary pressure. Contact angles, mean curvatures and capillary pressures all showed a shift from weakly oil-wet towards a mixed-wet state as more pore volumes of low salinity brine were injected into the sample. Overall, this study establishes a methodology to characterize and quantify wettability changes at the pore scale which appears to be the dominant mechanism for oil recovery by LSW.

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Section: Resultssupporting

confidence: 75%

Section: Resultsmentioning

confidence: 92%

“…7 b. This implies a mixed-wet system with good connectivity of the phases in the pore space 36 , 37 , 64 which results in enhanced oil flow and better recovery.

Figure 7 Measured oil–brine curvature distribution before and at the end of waterflooding using the principal curvatures (κ 1 and κ 2 ) obtained from all oil–brine interfaces.…”

Section: Resultsmentioning

confidence: 99%

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Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions

Selem

Agenet

Gao

et al. 2021

Sci Rep

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“…Zhao et al (2017) employed the CT and neutron radiography to characterize the influence of pore structure on the water imbibition in tight sandstones. Moreover, the 3D images of the flow evolution inside a rock sample have been reported by using high spatial and temporal resolution CT (Alhammadi et al, 2020;Alzahid et al, 2020;Gao et al, 2020;Iglauer & Lebedev, 2018;Joyce et al, 2015;Ju et al, 2018). Singh et al (2017) captured the snap-off process during imbibition using fast synchrotron X-ray CT and stated the process was favorable for a large aspect ratio of local pores.…”

mentioning

confidence: 99%

Investigation of Spontaneous Imbibition Behavior in a 3D Pore Space Under Reservoir Condition by Lattice Boltzmann Method

Zheng

Lei

et al. 2021

JGR Solid Earth

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Unconventional oil reservoirs, which are previously classified as uneconomic resources by traditional developing methods, have become one of the important world energy supplying parts in recent years with the application of horizontal drilling, hydraulic fracturing and numerous enhanced oil recovery (EOR) methods (K. Singh et al., 2019;Xie et al., 2021). These oil reservoirs usually bury deep underground with conditions characterized as high-pressure and high-temperature. In a typical unconventional oil reservoir exploitation, a hydraulic fracturing job is proceeded after the completion of horizontal drilling to increase transport channels for oil recovery (Z. Chen et al., 2020). Previously, a flowback operation of the fracturing fluid is usually designed to decrease the potential reservoir damage. However, recent developments in these oil fields showed that partly flowback or even no flowback with the subsequent shut-in operation increased the oil recovery (

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“…al. [16] used µ-CT imaging and differential pressure measurements, and designed a comparative study to measure relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions during steady-state waterflooding experiments. Relative permeabilities were calculated from the pressure differential measured during the experiment and the saturation calculated based on the images.…”

mentioning

confidence: 99%

Pore-network modeling and determination of rock and two-phase fluid flow properties

et al. 2021

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Pore-scale modeling is becoming widely applied in the oil industry. The objective of porescale imaging and modeling is to predict the properties of multiphase flow in porous media. Pore-network model construction of geologically realistic samples and determination of rock and two-phase fluid flow properties are described and discussed in this paper. Pore-network models were constructed using published micro-computed tomography images of different rock samples. Effective porosity, average absolute permeability, capillary pressure, tortuosity (in 3 directions), and relative permeability were calculated for 2 types of displacement (drainage and imbibition). Avizo® Software and two-phase code were used for volume rendering of rock samples and calculations of rock and two-phase fluid flow properties, since it is a valuable and reliable tool for prediction of petrophysical properties and has advances in visualization of the pore space. Created 3D models of core samples based on micro-computed tomography scan data will allow oil and oilfield service companies to create a digital core database on a computer instead of storing physical cores in warehouses, which in turn greatly facilitates access to cores for further work with them.

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Pore-scale imaging with measurement of relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions

Cited by 40 publications

References 45 publications

Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions

Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions

Investigation of Spontaneous Imbibition Behavior in a 3D Pore Space Under Reservoir Condition by Lattice Boltzmann Method

Pore-network modeling and determination of rock and two-phase fluid flow properties

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