Pore-Scale Distribution of Crude Oil Wettability in Carbonate Rocks

Marathe, Rohini; Turner, Michael L.; Fogden, Andrew

doi:10.1021/ef301088j

Cited by 31 publications

(15 citation statements)

References 35 publications

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“…On the other hand, the flat front face β in Figure 9f appears pristine and water-wet, as the extremely fine nanoparticle texture covering it is the platinum coat. This conforms to the pattern observed in a previous study of carbonate wettability (Marathe et al 2012), in which anhedral faces (such as α) become preferentially oil-wet while euhedral faces (such as β) remain water-wet. However, the other two faces in Figure 9f are euhedral, yet they bear some asphaltene, distributed either uniformly (γ) or sporadically (δ).…”

Section: Integration Of Sem Surface Images Into Tomogramssupporting

confidence: 91%

“…The mass of asphaltene remaining after bulk oil and brine extraction, and subsequently extracted with azeotropic chloroform/methanol, averages 0.23 mg/g (relative to dry plug mass) over the five plugs. This is fairly similar to the average of 0.40 mg/g asphaltenes extracted from four other reservoir carbonates in a previous study (Marathe et al 2012 …”

Section: Oil and Brine Contents From Extractionsupporting

confidence: 90%

“…Four plugs underwent extraction for measurement of their overall oil and brine volumes in this preserved-as-received state, using a variation of a published protocol for small rock samples (Marathe et al 2012), to be compared to digital analysis of the other plugs. Each of the four plugs was weighed and immersed in decalin (decahydronaphthalene) in a 3 ml glass vial with a bed of dry quartz sand (of known mass) at its bottom.…”

Section: Extraction Of Plugs and Analysis Of Extractsmentioning

confidence: 99%

“…As micro-CT cannot directly resolve surface chemistry or contact angles in pores of complex rocks, an alternative technique has been developed to visualize the pore-scale distribution of wettability-altering asphaltenes adsorbed or deposited from crude oil on pore walls after primary drainage or subsequent flooding. The characteristic nodule texture of the asphaltene "footprint", revealed by removing the overlying bulk oil and brine using weak solvents, was 2D imaged at the cut faces of sandstones and carbonates Marathe et al 2012) using high-resolution field emission scanning electron microscopy (FESEM).…”

Section: Introductionmentioning

confidence: 99%

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

et al. 2014

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3D pore-scale imaging and analysis provides an understanding of microscopic displacement processes and potentially a new set of predictive modeling tools for estimating multiphase flow properties of core material. Reconciliation and integration of the data derived from these models requires accurate characterization of the pore-scale distribution of fluids and a more detailed understanding of the role of wettability in oil recovery.The current study reports experimental imaging progress in these endeavors for a preserved-state carbonate core from a Middle Eastern waterflooded reservoir. Micro-CT methods were used in combination with novel fluid X-ray contrasting techniques and image registration to visualize the 3D pore-scale distribution of residual oil in mini-plugs. Segmentation of the registered tomograms and their differences facilitated estimation of the residual oil saturation. These predictions from digital analysis agreed reasonably well with laboratory measurements of oil saturation from extraction of sister mini-plugs and spectrophotometry. The tomogram segmentations provide additional information beyond this average value, such as the fractions of oil associated with macroporosity and microporosity.After the tomogram acquisitions, one of the dried mini-plugs was cut and SEM imaged at this exposed face to provide 2D images of fine features below the micro-CT resolution limit, such as the characteristic dimpled texture of asphaltene films on calcite surfaces due to their local wettability alteration in the reservoir. A new registration procedure was developed to embed the SEM images from the cut plug into the tomogram of the original uncut plug at their correct locations, so that this highresolution wettability information could be integrated into the 3D pore network description and correlated to the local distribution of residual oil.

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Section: Integration Of Sem Surface Images Into Tomogramssupporting

confidence: 91%

Section: Oil and Brine Contents From Extractionsupporting

confidence: 90%

Section: Extraction Of Plugs and Analysis Of Extractsmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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

et al. 2014

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“…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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Petrographic Imaging Methods for Characterizing Mudstone Reservoirs

Olson¹,

Milliken

2021

Encyclopedia of Petroleum Geoscience

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Pore-Scale Distribution of Crude Oil Wettability in Carbonate Rocks

Cited by 31 publications

References 35 publications

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

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

Pore‐scale modeling of wettability alteration during primary drainage

Petrographic Imaging Methods for Characterizing Mudstone Reservoirs

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