Pore-Scale Imaging of Oil and Wettability in Native-State, Mixed-Wet Reservoir Carbonates

Dodd, Nicole; Marathe, Rohini; Middleton, Jill; Fogden, Andrew; Carnerup, Anna M.; Knackstedt, Mark; Mogensen, Kristian; Marquez, Xiomara; Frank, Soren; Bounoua, Noureddine; Noman, Rashed

doi:10.2523/iptc-17696-ms

Cited by 10 publications

(7 citation statements)

References 13 publications

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“…Since wettability cannot be measured by direct methods, but indirectly by measurements of macroscopic behavior in the rock medium, pore-scale modeling that simulates fluid displacement behavior through pores and throats is used to predict microscopic fluid distribution, which is then related to the macroscopic parameters of wettability index and oil recovery (Jadhunandan, 1990;Morrow, 1990;Dunsmoir et al, 1991;Fassi-Fihri et al, 1995;McDougall and Sorbie, 1997;Dixit et al, 2000;AlFutaisi and Patzek, 2003;Zhao, 2010;Dodd et al, 2014;Wopara, 2016;Farrad et al, 2016;Alhammadi et al, 2017). It is therefore a useful tool for understanding the impact of rock structure and wettability on multiphase flow properties and oil recovery.…”

Section: Applications Of Pore-network Modelingmentioning

confidence: 99%

Review of studies on pore-network modeling of wettability effects on waterflood oil recovery

Wopara¹,

Iyuke²

2018

J. Petroleum Gas Eng.

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Waterflooding has become by far the most widely applied method for enhanced oil recovery, accounting for more than half of oil production worldwide. Changes in the wettability of a porous medium and the chemical composition of the wetting fluid result to changes in oil recovery. In recent time, pore-network modeling has been used increasingly to study the effect of wettability on waterflood oil recovery and multiphase flow properties in different types of petroleum reservoirs. Starting from single pore models of fluid arrangements, computations of relative permeability, interfacial area, mass dissolution rate and many other physical properties have been made. Using realistic representations of the pore spaces of various rock systems, it is now possible to predict many petro-physical properties that govern fluid flow and transport in petroleum reservoir rock systems. Such properties include porosity, permeability, waterflood relative permeability, capillary pressure, phase saturations, and fluid transfer coefficients. This review looks briefly into some of the successes made so far on pore network modeling, with an emphasis on models of wettability trends and oil recovery by waterflooding.

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Section: Applications Of Pore-network Modelingmentioning

confidence: 99%

Review of studies on pore-network modeling of wettability effects on waterflood oil recovery

Wopara¹,

Iyuke²

2018

J. Petroleum Gas Eng.

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“…The sub-plug was re-scanned by HeliScan micro-CT in this Milled state and registered to its original Dry tomogram. A surface projection algorithm (Dodd et al, 2014) was applied to obtain a 2D map of the milled face and its virtual location in the sub-plug prior to milling ( Figure 3d). The milled face was BSEM imaged (Helios, FEI) at 1 kV without conductive coating, using MAPS (FEI) software to acquire and stitch a mosaic of tiles at 10 nm/pixel to cover a central strip of 3.66 mm x 0.23 mm.…”

Section: Sem Imagingmentioning

confidence: 99%

“…The topographical height map obtained from the projection in turn provides the means to register these BSEM and mineral maps into their corresponding virtual location in 3D within the tomogram of the sub-plug prior to milling (Figure 3d). While the ion milling produced a very flat surface for this particular sample, the power of the projection method lies in its ability to also register SEM images of non-planar surfaces (Dodd et al, 2014), e.g. with ridges or conical profile from sub-optimal ion milling, into tomograms.…”

Section: Integration Of Higher Resolution Information Into Tomogramsmentioning

confidence: 99%

Applications of Multi-Scale Imaging Techniques to Unconventional Reservoirs

et al. 2015

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Understanding and prediction of hydrocarbon transport within the matrix of unconventional tight reservoirs demands an integrated imaging strategy spanning from the smallest nanoscale pores to plug scale and beyond. Recent developments in multi-scale imaging are presented for Barnett shale samples to illustrate this approach to upscaling. The utility of micro-CT imaging for shales can be extended by X-ray contrast enhancement techniques coupled with tomogram registration. In particular, saturation of a shale plug with a highly attenuating liquid and subtraction of this tomogram from the registered dry-state tomogram yields a 3D voxel map of connected porosity over the plug. The same procedure can be applied to sub-plugs sampled from the parent plug to capture micron-scale variations in porosity. This approach does not directly provide the size, shape and connectivity of individual pores, since the vast majority of shale pores remain below tomogram resolution even for small sub-plugs. Two approaches to access this higher-order information are addressed. The first uses the state of the shale sub-plug saturated with X-ray dense liquid as the starting point for dynamic micro-CT imaging of the diffusion of a second, miscible, X-ray transparent liquid into the sub-plug. This can reveal the presence of faster pathways of transport through pores of larger size or lower tortuosity. The second approach involves broad beam ion-milling of the sub-plug for acquisition of 2D BSEM image mosaics and mineral maps, and their registration into the corresponding section of the 3D tomograms. This provides a registered basis for upscaling of transport properties, e.g. simulated from small FIB-SEM cubes, to sub-plug and in turn to plug via their micro-CT porosity maps. Very high resolution SEM imaging of broken surfaces can provide useful complementary information as to the finest scale of organic-hosted nanopores. The Barnett shale samples exhibited fairly homogeneous distributions of porosity on the plug and sub-plug scales, and also displayed relatively uniform diffusion across the sub-plug, suggesting that they are amenable to characterization and upscaling using only a limited set of parameters. This homogeneity is thought to be due in significant part to the predominance of organic-hosted porosity and to the structural uniformity of these nano-scale organic pore networks.

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“…There are common claims that micropores always maintain their strong affinity to water [ Fassi‐Fihri et al ., ]. Yet oil has been detected within micropores in carbonate rocks, making oil‐wet conditions plausible [ Al‐Yousef et al ., ; Clerke , ; Clerke et al ., ; Dodd et al ., ; Fung et al ., ; Knackstedt et al ., ]. An oil‐wet state may have developed either over geological time in large oil columns where high enough capillary pressures are reached, or as remnant distributions in initially larger pores, or if the micropores undergo progressive wettability changes.…”

Section: Introductionmentioning

confidence: 99%

“…Although wettability is known to be heterogeneous on a pore‐to‐pore scale [ Fassi‐Fihri et al ., ], current contact angle measurement techniques are unable to discriminate the pore‐scale distribution of wettability in natural porous media. Imaging techniques such as Cryo‐SEM [ Al‐Yousef et al ., ; Fassi‐Fihri et al ., ] and Field‐Emission SEM (FESEM) [ Dodd et al ., ; Knackstedt et al ., ; Marathe et al ., ] can, however, be used for qualitative wettability analysis and attempts to identify wetting patterns. Examination of the wetting state of micropores is particularly important, as these may dominate the connected pore system in many carbonate reservoirs [ Cantrell and Hagerty , ].…”

Section: Introductionmentioning

confidence: 99%

Pore‐scale modeling of wettability alteration during primary drainage

Kallel

Dijke

Sorbie

et al. 2017

Water Resources Research

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While carbonate reservoirs are recognized to be weakly‐to‐moderately oil‐wet at the core‐scale, pore‐scale wettability distributions remain poorly understood. In particular, the wetting state of micropores (pores <5 µm in radius) is crucial for assessing multiphase flow processes, as microporosity can determine overall pore‐space connectivity. While oil‐wet micropores are plausible, it is unclear how this may have occurred without invoking excessively high capillary pressures. Here we develop a novel mechanistic wettability alteration scenario that evolves during primary drainage, involving the release of small polar non‐hydrocarbon compounds from the oil‐phase into the water‐phase. We implement a diffusion/adsorption model for these compounds that triggers a wettability alteration from initially water‐wet to intermediate‐wet conditions. This mechanism is incorporated in a quasi‐static pore‐network model to which we add a notional time‐dependency of the quasi‐static invasion percolation mechanism. The model qualitatively reproduces experimental observations where an early rapid wettability alteration involving these small polar species occurred during primary drainage. Interestingly, we could invoke clear differences in the primary drainage patterns by varying both the extent of wettability alteration and the balance between the processes of oil invasion and wetting change. Combined, these parameters dictate the initial water saturation for waterflooding. Indeed, under conditions where oil invasion is slow compared to a fast and relatively strong wetting change, the model results in significant non‐zero water saturations. However, for relatively fast oil invasion or small wetting changes, the model allows higher oil saturations at fixed maximum capillary pressures, and invasion of micropores at moderate capillary pressures.

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Pore-Scale Imaging of Oil and Wettability in Native-State, Mixed-Wet Reservoir Carbonates

Cited by 10 publications

References 13 publications

Review of studies on pore-network modeling of wettability effects on waterflood oil recovery

Review of studies on pore-network modeling of wettability effects on waterflood oil recovery

Applications of Multi-Scale Imaging Techniques to Unconventional Reservoirs

Pore‐scale modeling of wettability alteration during primary drainage

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