Low-permeability reservoir sample wettability characterization at multiple scales: Pore-, micro- and macro-contact angles

Pan, Bin; Clarkson, Christopher R.; Debuhr, Chris; Younis, Adnan; Song, Chengyao; Ghanizadeh, Amin; Birss, Viola I.

doi:10.1016/j.jngse.2021.104229

Cited by 24 publications

(15 citation statements)

References 45 publications

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“…The contact angle and wetting area, two variables that directly determine wettability, are reasonably considered in this rock model because the factors influencing rock wettability (minerals, chemistry, pressure, temperature, etc. ), which ultimately act on the change of contact angle and wetting area, are fully considered …”

Section: Petrophysical Model and Numerical Simulation Schemementioning

confidence: 99%

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Mixed Wettability Modeling and Nuclear Magnetic Resonance Characterization in Tight Sandstone

et al. 2023

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Rock wettability significantly impacts fluid distributions in reservoirs and enhanced oil recovery. As the large variety of mixed-wet tight formations becomes increasingly evident, research evaluating wettability has become increasingly important. The nuclear magnetic resonance (NMR) technique is suitable for wettability characterization, but the simplified rock models currently used in NMR studies, that is, entirely water-wet or oilwet or classified as water-or oil-wet based on pore geometry, may result in inaccurate pore-fluid distributions and wettability estimates. In this paper, a new pore-scale mixed-wet rock model was constructed that considers the contact angle and wetting area. A tight sandstone rock saturated with oil−water is presented as an example to investigate T 2 responses and NMR T 2 -based wettability indices for different wettability features. In the model, a mixed-wet digital rock saturated with oil and water is constructed using the sedimentological process method and the Lattice Boltzmann method. Then, the random walk method is applied to simulate T 2 responses in cases with varied wettability properties, such as contact angle, wetting area ratio, and fluid saturation. Finally, the apparent contact angle cosine is used as the wettability indicator for comparison with published NMR T 2 -based wettability indices. The results showed that the combination of the wetting area ratio (determined by the pore size cutoff), actual contact angle of wetting surfaces, and fluid saturation significantly impacted T 2 distributions of fluid-saturated mixed-wet rocks. Simulations and experiments showed that three NMR T 2 -based wettability indices were inappropriate for wettability assessment in weakly wet or intermediate-wet rocks. This was because those NMR indices are based on wetting areas and do not account for the effect of local contact angles of wetting surfaces. These investigations have provided a theoretical basis for interpreting NMR T 2 characterizations in rocks with mixed wettability.

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Section: Petrophysical Model and Numerical Simulation Schemementioning

confidence: 99%

“…), which ultimately act on the change of contact angle and wetting area, are fully considered. 51 3.2. Construction of Fluid Distribution.…”

Section: Petrophysical Model and Numerical Simulation Schemementioning

confidence: 99%

Mixed Wettability Modeling and Nuclear Magnetic Resonance Characterization in Tight Sandstone

et al. 2023

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“…Contact angle is a scale-dependent parameter, that is, macroscale contact angles measured on flat surfaces may differ significantly from micro- and nanoscale contact angles at in situ porous rocks, ,, because of line tension and local heterogeneity. , Thus, it is suggested to use advanced imaging techniques (such as microcomputed tomography , and nuclear magnetic resonance − ) to further study wettability inside in situ porous rocks in the future. However, the resolution of the advanced imaging equipment is still not powerful enough to visualize a three-phase contact line clearly at nano-scale .…”

Section: Research Gaps and Future Outlookmentioning

confidence: 99%

Mini Review on Wettability in the Methane–Liquid–Rock System at Reservoir Conditions: Implications for Gas Recovery and Geo-Storage

Pan

Zhu

et al. 2022

Energy Fuels

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Wettability in the methane (CH4)–liquid–rock system is a key parameter which determines gas recovery and geo-storage efficiencies. However, there is a lack of an overview over this area; thus, we critically review this parameter from experimental and theoretical perspectives and discuss the impact of pressure and temperature conditions, fluid properties (salinity, ion type, and aqueous versus nonaqueous) as well as rock surface chemistry and roughness. Current research gaps are identified, a future outlook is provided, and several conclusions are reached. Therefore, this mini review improves fundamental understanding of wettability in the CH4–liquid–rock system at in situ reservoir conditions and provides useful guidance on the areas of shale gas/coalbed methane recovery and natural gas geo-storage.

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“…More specifically, the soluble minerals in the rock are partially dissolved by the reaction with water, which has a certain effect on the SI of water, − and the previous studies’ results show that the salinity of water also has a great influence on SI. − In addition, clay minerals typically swell to a certain extent when in contact with water, complicating the pore structure of shale (e.g., blocking pores and throats) and sometimes reducing fluid migration rates. , For homogeneous porous media, the greater the tortuosity of the connected pore system, the longer the migration path of solute molecules through the same linear distance in the porous medium and the smaller the imbibition slope . Due to the strong heterogeneity and complex pore structure of shale with the coexistence of organic matter pores and inorganic pores, shale reservoirs often exhibit mixed wettability (Dalmatian wettability), which in turn affects the SI behavior. , The wettability and pore connectivity of shale reservoirs were previously evaluated by SI experiments. , However, the application of SI on the enrichment mechanism of hydrocarbons is quite limited. SI experiments, which can be treated as physical simulation experiments of fluid migration and accumulation in shale reservoirs to some extent, have the advantage of simple sample preparation, dynamic recording of changes in the imbibed fluid volume, and low costs.…”

Section: Introductionmentioning

confidence: 99%

Using Spontaneous Imbibition to Evaluate the Hydrocarbon Migration and Accumulation Potential of Shale Reservoirs: A Case Study of the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin

Wang

Gao

et al. 2022

Energy Fuels

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Spontaneous imbibition (SI) has been used widely to characterize shale wettability and pore structures, which can significantly affect the migration and accumulation processes of shale oil. However, the application of SI in the enrichment mechanism of shale oil is quite limited. Therefore, focusing on the Permian Fengcheng Formation shale deposited in an alkaline lake environment in the Mahu Sag of Junggar Basin, this study conducts systematic SI experiments with complementary experiments such as contact-angle measurement, optical microscopy, field emission scanning electron microscopy, micro-CT, high-pressure mercury intrusion porosimetry, and N 2 adsorption to clarify the controlling factors of SI behavior of different fluids in shale and attempts to evaluate the migration and accumulation potential of shale reservoirs using SI. The results show that the more hydrophobic the sample is, the stronger the absorption of n-decane is, and the SI of n-decane reaches equilibrium quickly. The development of an alkaline mineral layer that is several millimeters thick in Fengcheng Formation shale could promote hydrocarbon migration due to the large particles of alkaline minerals (200−400 μm) and more development of intergranular microfractures, which can be indicated by the higher SI slope and imbibed oil volume. Using SI parameters, the shale hydrocarbon migration−accumulation index H m was proposed in this study; the greater the H m of the shale reservoir is, the more conducive to the migration and accumulation of shale oil the shale reservoir is. Four migration−accumulation patterns were established for different lithofacies in the study area, and the migration and accumulation potential of different lithofacies of shale from strong to weak is in the order of siltstone, shale with an alkaline mineral layer, laminated shale, and then massive shale, which is generally in line with the order of shale oil content. The validity of the proposed shale hydrocarbon migration−accumulation index is also confirmed using data from the literature.

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Low-permeability reservoir sample wettability characterization at multiple scales: Pore-, micro- and macro-contact angles

Cited by 24 publications

References 45 publications

Mixed Wettability Modeling and Nuclear Magnetic Resonance Characterization in Tight Sandstone

Mixed Wettability Modeling and Nuclear Magnetic Resonance Characterization in Tight Sandstone

Mini Review on Wettability in the Methane–Liquid–Rock System at Reservoir Conditions: Implications for Gas Recovery and Geo-Storage

Using Spontaneous Imbibition to Evaluate the Hydrocarbon Migration and Accumulation Potential of Shale Reservoirs: A Case Study of the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin

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